Phillips Chemical Company - US EPA€¦ · Chevron Phillips Chemical Company LP Gulf Coast Steam Cracker – Greenhouse Gas Air Permit Application FINAL GHG Application 12.19.11.docx

SEE Solutions, LLC 11601 Shadow Creek Pkwy, Suite 111 Pearland, Texas 77584

Chevron Phillips Chemical Company LP Cedar Bayou Plant New Ethylene Unit 1594 Greenhouse Gas PSD Permit Application December 2011

Chevron Phillips Chemical Company LP Gulf Coast Steam Cracker – Greenhouse Gas Air Permit Application

FINAL GHG Application 12.19.11.docx.doc

TABLE OF CONTENTS

1.0 INTRODUCTION ................................................................................................................. 1

2.0 ADMINISTRATIVE INFORMATION AND ASSOCIATED FORMS ............................................... 2

3.0 AREA MAP AND PLOT PLAN ............................................................................................... 5

4.0 PROCESS DESCRIPTION ...................................................................................................... 9 4.1 Ethylene Unit ......................................................................................................................... 9 4.2 VHP Boiler ............................................................................................................................ 11 4.3 Low Pressure Vent System and Vapor Destruction Unit ..................................................... 11 4.4 Low Profile Flare System ..................................................................................................... 11 4.5 Emergency Generator.......................................................................................................... 12 4.6 Storage Tanks ....................................................................................................................... 12 4.7 Cooling Tower ...................................................................................................................... 12 4.8 Wastewater Collection and Treatment System ................................................................... 12 4.9 Miscellaneous Utilities ........................................................................................................ 13

5.0 EMISSIONS ESTIMATES ......................................................................................................17 5.1 Steam Cracking Furnaces ..................................................................................................... 17 5.2 VHP Boiler ............................................................................................................................ 18 5.3 Vapor Destruction Unit ........................................................................................................ 19 5.4 Low Profile Flare .................................................................................................................. 19 5.5 Emergency Generators ........................................................................................................ 20 5.6 Piping Fugitives .................................................................................................................... 20

6.0 BEST AVAILABLE CONTROL TECHNOLOGY ANALYSIS .......................................................... 26 6.1 Steam Cracking Furnaces ...................................................................................................... 27 6.2 Decoking Activities .............................................................................................................. 30 6.3 VHP Boiler ............................................................................................................................ 31 6.4 Vapor Destruction Unit ........................................................................................................ 33 6.5 Low Profile Flare .................................................................................................................. 35 6.6 Emergency Generators ......................................................................................................... 37 6.7 Piping Fugitives .................................................................................................................... 39

7.0 OTHER PSD REQUIREMENTS ............................................................................................ 42

Appendix A Emissions Estimates Appendix B RACT/BACT/LAER Clearinghouse Search Results


FINAL GHG Application 12.19.11.docx 1

1.0 INTRODUCTION Chevron Phillips Chemical Company LP (Chevron Phillips) owns and operates an olefins and polyolefins complex at Cedar Bayou in Harris County. This facility currently operates an ethylene cracking unit, polyethylene units, and normal‐ and polyalphaolefins manufacturing units. Chevron Phillips proposes to expand its olefins production capacity at the Cedar Bayou Plant by constructing new ethylene steam cracking furnaces and supporting equipment. The modification will include an additional design production capacity of approximately 1.5 million metric tonnes per year of polymer grade ethylene. Other products include fuel gas, a C3+ stream, and other small hydrocarbon streams. Chevron Phillips proposes to initiate construction on this ethylene cracking unit expansion in November 2014, with final construction and startup by 2017.

The proposed expansion represents a major modification to an existing major source with respect to Nonattainment New Source Review (NNSR) for the ozone precursors nitrogen oxide (NOx) and volatile organic compounds (VOC), as well as Prevention of Significant Deterioration (PSD) review for NOx, carbon monoxide (CO), particulate matter (PM), and sulfur dioxide (SO2). Additionally, as compared to the contemporaneous baseline, the project represents an increase in the potential to emit (PTE) greenhouse gases (GHGs) above the significance levels established by the U.S. Environmental Protection Agency (EPA) in its PSD Tailoring Rule of June 3, 2010. Likewise, there are no significant decreases in GHGs in the contemporaneous period that could potentially result in the project’s netting out of GHG PSD review. Therefore, detailed GHG contemporaneous netting is not included in this application.

Chevron Phillips has submitted a new source review permit amendment application to the Texas Commission on Environmental Quality (TCEQ) to authorize construction of this olefins unit expansion and its associated emissions of NOx, CO, VOC, PM, and SO2. The TCEQ permit amendment will incorporate NNSR for ozone (with VOC and NOx as regulated precursors) as well as PSD review for NOx, CO, PM, and SO2. Pursuant to the EPA Tailoring Rule, Chevron Phillips is also submitting this PSD application for the expansion project to EPA to authorize the project’s GHG emissions.

The balance of this permit application includes the following sections:

2.0 Administrative Information and Associated Forms

3.0 Area Map and Plot Plan

4.0 Process Description

5.0 Emissions Estimates

6.0 Best Available Control Technology Analysis

7.0 Other PSD Requirements



2.0 ADMINISTRATIVE INFORMATION AND ASSOCIATED FORMS

As required by 40 CFR §52.21(n), Chevron Phillips is providing administrative information related to this permit application on the following form. This information includes:

Company name;

Company official and associated contact information;

Technical contact and associated contact information;

Project location, Standard Industrial Code (SIC), and North American Industry Classification System (NAICS) code;

Projected start of construction and start of operation dates; and

Company official signature transmitting the application.

Additionally, in this section Chevron Phillips also provides a summary table demonstrating the project’s PSD applicability with respect to the Tailoring Rule requirements.

GHGPSDApplicabilitySummary

PermitNo.: TBD ApplicationSubmittalDate: December 19, 2011

Company: Chevron Phillips Chemical Company, LP

FacilityLocation: 9500 Interstate 10 East

City: Baytown County: Harris

PermitUnitI.D.:New Cracking Furnaces, Boiler, VDU, Flare, Piping Fugitives, and Emergency Generators

PermitName: Ethylene Unit 1594

PermitActivity: NewSource Modification

ProjectorProcessDescription:Ethylene Unit 1594 Expansion

CompleteforallPollutantswithaProjectEmissionIncrease. POLLUTANTS

Ozone CO PM10 NOX SO2 Other1

CO2e VOC NOX

Nonattainment? yesorno NO NO NO

ExistingsitePTE tpy ? >100,000

Proposedprojectemissionincreases tpy 1,607,000

Istheexistingsiteamajorsource2?Ifnot,istheprojectamajorsourcebyitself2? yesorno

Yes

Ifsiteismajor,isprojectincreasesignificant? Yes

Ifnettingrequired,estimatedstartofconstruction? November 2014 (Netting not relied upon for this permit)

Fiveyearspriortostartofconstruction November 1999 contemporaneous

Estimatedstartofoperation November 2016 period

Netcontemporaneouschange,includingproposedproject tpy >100,000

FNSRAPPLICABLE? yesorno Yes (PSD)

1 OtherPSDpollutants.2 40CFR§52.21 b 49 v .



3.0 AREA MAP AND PLOT PLAN

An area map is provided in Figure 3‐1 which details 3,000‐feet distance markings. An overall plot plan of the Cedar Bayou Plant is provided in Figure 3‐2 which details the location of the facilities referenced in this submittal. Additionally, Chevron Phillips owns other property in the area that is not marked because it is not currently fenced. Figure 3‐3 is a detailed plot plan showing the new Unit 1594 equipment and associated facility identification numbers/emission point numbers (FINs/EPNs).

309500 310000 310500 311000 311500 312000 312500 313000 313500 314000 314500 315000 315500 316000 316500 317000 317500 318000 318500

UTM Easting (meters)

3299

000

3299

500

3300

000

3300

500

3301

000

3301

500

3302

000

3302

500

3303

000

3303

500

3304

000

UT

M N

orth

ing

(met

ers)

FIGURE 2-1Area Map

Cielo Center1250 South Capital of Texas HighwayBuilding Three, Suite 200Austin, Texas 78746, USA

Chevron Phillips Chemical Company LP

Source: mytopo.com/Zone: 15Map: Mont Belvieu

North

Property Line

3,000 ft

Scale

(feet)0 1000 2000 3000 4000 5000 3-1

Unit 1594

3-2

Chevron PhillipsChemical Company LP

Figure 2-3Unit 1594 - Plot Plan

Cielo Center 1250 South Capital of Texas Highway Building Three, Suite 200 Austin, Texas 78746, USA

H-10100

H-10200

H-10300

H-10400

H-10500

H-10600

H-10700

H-10800

B-83010PK-90060

TK-87010AXTK-87010AF-1594

TK-93041

PK-84010PK-87010CKPK-87010CPK-87010B

PK-87010BX

PK-90050

3-3



4.0 PROCESS DESCRIPTION This section describes the process for the new ethylene unit (Unit 1594) and supporting utilities. A simplified process flow diagram for the ethylene unit is included as Figure 4‐1. Figure 4‐2 provides a simplified process flow diagram for the associated wastewater collection and treatment system. A completed materials balance table, which shows the materials and rates associated with specified points on the process flow diagram, is provided in Table 4‐1 at the end of this section. Represented feed and product rates in the materials balance table are not intended as enforceable limits as production rates can vary depending on the feed and associated operating conditions.

4.1 Ethylene Unit

4.1.1 Feed Preparation

Fresh ethane feed from storage is filtered and dewatered in a coalescer before going through ethane feed dryers. Typically, two dryers will be in operation at any given time and the third will be on regeneration or standby. After the ethane is dried, it is chilled on its way to the ethane feed flash drum. Liquid from the flash drum is mixed with recycle ethane and the combined stream is preheated and mixed with the vapor from the flash drum as feed for the cracking furnaces.

4.1.2 Furnace Section

The cracking furnaces consist of eight (8) proprietary Ultra Selective Conversion induced draft furnaces (EPNs H‐10100 to H‐10800). The unit typically operates with seven furnaces with one furnace available for decoking and hot steam standby. The furnaces are equipped with low NOx burners and selective catalytic reduction (SCR) systems to control NOx emissions. Continuous Emission Monitoring Systems (CEMS) for NOx, CO, and oxygen, will be installed on each furnace. The pyrolysis of hydrocarbons forms coke in the heater tubes that must be periodically removed by using steam/air decoking. The furnaces typically operate for approximately fifty days before being taken off‐line for decoking. The decoking procedure oxidizes and spalls the coke. Furnace fuel is plant fuel gas supplemented by natural gas.

4.1.3 Quench Water System

The quench water (QW) tower receives the cracking furnace effluent, condenses the dilution steam from the cracked gas, segregates the heavy components, and recovers the process surplus heat against other suitable process streams. The water/hydrocarbon mixture from the bottom of the QW tower is routed to an oil/tar/water separation system. The oil/tar mixture from the separation is routed to tanks where it is collected for subsequent processing in an existing unit. Water from the separation system is recycled to the QW tower. A blowdown stream from the recycled water is routed to the benzene stripper and then to new wastewater treatment units.



4.1.4 Cracked Gas Compression

The cracked gas compression system utilizes a five‐stage compressor which is driven by a steam turbine. The overhead from the QW Tower is mixed with recycled methane from the demethanizer system and is fed to the first stage suction drum to remove liquid droplets that are entrained in the cracked gas. The cracked gas is then fed to the first stage of the cracked gas compressor and the vapor proceeds through the fourth stage of the compressor before being routed to the caustic wash system.

4.1.5 Caustic Wash System

The acid gases such as CO2 and/or H2S must be removed from the cracked gas to meet ethylene product specifications, and to protect the acetylene hydrogenation catalyst from H2S poisoning. The caustic tower consists of four sections; three lower sections are used for caustic scrubbing and the top section is use for washing the treated gas to avoid caustic carryover to the downstream equipment. Spent caustic is deoiled and degassed to flash dissolved light hydrocarbons. Degassed spent caustic is sent to the spent caustic tank. Vapor from the caustic tower proceeds to the fifth stage of the cracked gas compressor.

4.1.6 Dehydration

The cracked gas dehydrator system has two vessels containing molecular sieves, with one in operation and the other on regeneration/standby. The molecular sieves are regenerated by heating the bed with warm tail gas. The effluent from the operating molecular sieve is cooled to separate condensed water from the gas. The condensed water is sent to the QW Tower. The vapor proceeds to the fuel gas system.

4.1.7 HP Deethanizer & LP Stripper

The dried cracked gas vapor is fed to the high pressure (HP) deethanizer. The uncondensed vapor, consisting of C2s and lighter components, passes to the acetylene hydrogenation system. The HP deethanizer bottoms are routed to the low pressure (LP) C2 stripper. The C2s in the bottoms of the HP deethanizer are recovered in the LP C2 stripper and recycled to the cracked gas compressor third stage discharge. The C3+ bottoms product from the LP stripper are routed to the distillation section of the existing Unit 1592 ethylene plant.

4.1.8 Acetylene Hydrogenation

The HP deethanizer overhead is heated before passing to the acetylene reactors. There are two reactors operating in series. These reactors convert acetylene to ethylene/ethane. The effluent of the first reactor is cooled before entering the second reactor. The gas is then dried before passing to the demethanization system.



4.1.9 Demethanization System

In the demethanization system, condensing and separation of the C2 and heavier components from the cracked gas is done in the chilling train, by use of progressively colder levels of ethylene, propylene, and process refrigeration in plate fin exchangers. The liquid condensates thus formed are already partially fractionated via the chilling train and are fed forward to the demethanizer tower. The bottoms from the demethanizer tower are routed to the C2 splitter. The overhead stream from the demethanizer tower is used as fuel gas for the cracking furnaces and, as needed, the very high pressure (VHP) boiler.

4.1.10 C2 Splitter and Heat Pump System

The C2 splitter is a low‐pressure ethylene‐ethane superfractionator that is part of an open‐loop heat pump system that is integrated with the ethylene refrigeration system. The fractionation in the C2 splitter separates ethylene/ethane feed into a high purity ethylene overhead vapor product stream and an ethane bottoms stream for recycle cracking.

4.1.11 Ethylene and Propylene Refrigeration

The ethylene refrigeration (C2R) system supplies process chilling at three levels. The propylene refrigeration (C3R) system supplies process chilling at two levels. Both the C2R refrigerant/heat pump compressor and the C3R compressor are driven by steam turbines.

4.2 VHP Boiler

The VHP boiler (EPN B‐83010) designed to supply very high pressure steam to the cracker during start‐up. Also, low pressure vent streams collected throughout the cracker plant are routed to the boiler firebox for control. The boiler is equipped with ultra‐low NOx burners, an SCR system, and NOx, CO, and oxygen CEMS, with ammonia slip calculated by mass balance.

4.3 Low Pressure Vent System and Vapor Destruction Unit

Low pressure vent streams from various points in the process are collected and routed to the firebox of the VHP boiler for destruction. For periods when the boiler is down, the low pressure vent streams are routed to a backup vapor destruction unit (VDU) (EPN PK‐90060) while maintenance or inspections are conducted on the boiler.

4.4 Low Profile Flare System

The low profile flare is designed for the safe control of gases vented from the ethylene cracker and support units. The low profile flare consists of multiple stage rows with several high capacity burners on each row. There is one staged burner for low pressure vents such as sweep gas, fugitive‐like sources such as “leak by” from safety relief and pressure control valves, small volume maintenance activities such as clearing small volume equipment such as pumps, analyzers, instruments, and associated piping. The high capacity burners handle high pressure discharges due to emergencies, start‐up and shutdown operations, and other large volume



maintenance clearing. The system is equipped with a totalizing flow meter and an on‐line analyzer to speciate the hydrocarbons in the flare gases, including Highly Reactive Volatile Organic Compounds (HRVOCs).

4.5 Emergency Generator

The ethylene unit includes three emergency generators, with an approximate aggregate power output of 4 MW total. The units are each powered by a diesel engine and there is one diesel tank associated with each emergency generator. Each generator engine’s normal operation is to run one hour per week to test for proper operation, in the event it needs to be used in an emergency situation.

4.6 Storage Tanks

The cracker plant has one spherical (pressurized) tank for C3+ product storage. There are ten nitrogen blanketed tanks including the spent caustic tank, two benzene stripper tanks, the oily wastewater equalization tank, two slop oil tanks, the sludge holding tank and a sulfiding agent tank. The sulfiding agent is used as an additive in the process. All these tanks vent to the low pressure vent system. The cracker plant includes additional tanks, which vent to atmosphere, that are in wastewater and utility service. These tanks are not expected to contain hydrocarbons.

4.7 Cooling Tower

The cooling water system supplies cooling water to the plant. The cooling water is used to cool exchangers and condensers. The cooling tower (EPN PK‐84010) is a multi‐cell, induced draft, counter‐flow type cooling tower.

4.8 Wastewater Collection and Treatment System

There are six oily wastewater and chemical wastewater sumps located throughout the cracker plant (Unit 1594) that collect process wastewater from sources such as pump pans, minor equipment leaks, and drains. These sumps are covered, sealed, and nitrogen blanketed with the sump vents discharging to the low pressure vent system. The wastewater from the sumps is sent to the oily wastewater equalization tank.

Spent caustic is treated in a wet air oxidation (WAO) system to convert sulfides to sulfates prior to being routed to the oily water equalization tank. The WAO system vents to the low pressure vent system.

Contact storm water (PC storm water) is collected from sections of ethylene unit 1594 where liquid hydrocarbons may wash from equipment surfaces or other sources to the concrete pad. There are four PC storm water sumps which collect and pump storm water to the PC stormwater equalization tank. The system is designed to collect the first flush of storm water and allow any remaining storm water to overflow to the clean storm water sewers and ditches.



The oily wastewater equalization tank pumps and PC storm water equalization tank pumps send wastewater to a corrugated plate interceptor (CPI) oil/water separator system. The CPI is a sealed unit and is nitrogen blanketed with vapors going to the low pressure vent system. Wastewater effluent from the CPI discharges to an induced gas floatation (IGF) unit. Vapors from the IGF unit are routed to the low pressure vent system. The IGF effluent is sent to an aerobic bio‐treatment unit and clarifier.

The benzene stripper system provides treatment to wastewaters whose sources contain benzene at 10 ppm or more. These streams are collected, pretreated in an IGF unit, and then sent to the benzene stripper equalization tanks, which are vented to the low pressure vent system. The effluent of the equalization tank is sent to the benzene stripper. Overheads from the benzene stripper are recycled to the QW tower. Stripped wastewater is routed to the aerobic bio‐treatment unit and clarifier mentioned above.

4.9 Miscellaneous Utilities

Various utilities will be constructed in support of the new ethylene unit that do not have air emissions and so do not require permit authorization by the TCEQ. These include a raw water treatment system, a demineralized water system, and plant air/instrument air systems.

inlet�feed QW�TOWER

FLASH�DRUMrecycle�methane

steam

EPN�H�10100�to�10800

3 R2

EIGHT�(8)�CRACKING�FURNACES

FILTERS�&�DRYERS

recycle ethane

COMPRESSION�STAGES�1�4

FEED�PREHEAT

blowdown to�benzene�stripper/WWT

water1

11

R1

recycle�ethane

OIL�&�TAR�SEPARATION

HP�DEETHANIZERDRYER

oil/tar�to�oil�slop�drum

off�gas�to�fuel

recycle�methane7

8 R2

spent�caustic�to WWTCAUSTICCOMPRESSION

DRYER

COLD�BOX

OVERHEAD�SYSTEMcaustic

210

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COMPRESSION�STAGE�5DEHYDRATOR�

SYSTEMACETYLENE�REACTORSCHILLER

C2�recycle

UNIT 110 FUGITIVES VHP BOILERDEMETHANIZER

SYSTEM ethylene�productLP�STRIPPERDEMETHANIZER

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UNIT�110�FUGITIVESEPN�F�1594

VAPOR�DESTRUCTION�UNIT

COOLING�TOWEREPN�PK�84010

LOW�PROFILE�FLAREEPN�PK�90050

VHP�BOILEREPN�PK�83010

5

Figure�5�1Process�Flow�Diagram

C3+�product�to�existing�

Ethylene�Unit�1592

C2�SPLITTER

recycle�ethane

EPN�PK�90060

EMERGENCY�GENERATOR�ENGINESEPNs�PK�87010�A/B/C

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Storm�Water� PC�Storm�Water�Equalization

Clean�Storm�Water�&�Utility�Wastewater�Sewer

Diversion�Sumps Equalization�Tank�(TK�93041)

Process�Oily�Water Sumps

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CPI�(PK�93050)

IGF�(PK�93060)

Bio�Treatment�Unit (PK�93070) OutfallWater�Sumps

Spent�Caustic�Tank(TK�34055)

Tank�(TK 93040)

WAO�(PK�92010)

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Benzene� Benzene�Stripper

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Diagram

4-2

This material balance table is used to quantify possible emissions of air contaminants and special emphasis should be placed on potential aircontaminants, for example: If feed contains sulfur, show distribution to all products. Please relate each material (or group of materials) listed to itsrespective location in the process flow diagram by assigning point numbers (taken from the flow diagram) to each material.

LIST EVERY MATERIAL INVOLVED IN EACH OF THE FOLLOWING GROUPS

Point No. from Flow Diagram

Process Rate (lbs/hr or SCFM) standard conditions: 70°F 14.7 PSIA. Check

appropriate column at right for each process.

Mea

sure

men

t

Est

imat

ion

Cal

cula

tion

1. Raw Materials - Input

Ethane, propane 1Fresh Caustic 2 640,000 lb/hr XProcess water 3

2. Fuels InputNatural Gas 4 2,400 scfm X

3. Products & By-Products - Output

Ethylene 5C3+ Product 6 590,000.0 lb/hr X

Tail Gas to Fuel 8

TABLE 4-1MATERIAL BALANCE

4. Solid Wastes - Output

Spent catalysts, oil, tar, coke, spent dehydrator media, wastewater

treatment sludges, maintenance wastes 9 TBD

5. Liquid Wastes - OutputX

Wastewater effluent 53,000 lb/hr

6. Airborne Waste (Solid) - Output

7. Airborne Wastes (Gaseous) - OutputGHGs (CO2, CH4, N2O, CO2e) X

Note: Throughput rates are representative of expected operations and should not be considered enforceable limits.

See Table 5-1



5.0 EMISSIONS ESTIMATES

Some of the proposed equipment discussed in Section 4.0, Process Description, is not expected to emit GHGs. Therefore, the following discussion includes only those proposed emissions units with an anticipated potential to emit (PTE) one or more GHGs. The GHGs emitted from ethylene cracking Unit 1594 will include carbon dioxide (CO2), methane (CH4), and nitrous oxide (N2O). Chevron Phillips does not anticipate emissions of hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), or sulfur hexafluoride (SF6) from the new ethylene cracker process, Unit 1594.

As discussed in more detail in the following sections, the estimated GHG PTE from Unit 1594 is 1,607,000 tons/yr of CO2 equivalent (CO2e). Table A‐1 in Appendix 1 further summarizes these emissions by individual GHG annual mass rates as well as corresponding annual CO2e rates from the following GHG‐generating emissions units:

Cracking furnaces,

VHP boiler,

Vapor destruction unit,

Low profile flare,

Routine emergency generator testing, and

Fugitive emissions from piping components in GHG service.

Chevron Phillips estimated CO2e emissions based on the estimated annual mass rates for each applicable GHG multiplied by the global warming potential (GWP) for each specific GHG as provided in Table A‐1 of Subpart A of 40 CFR part 98.

Table 5‐1, at the end of this section, provides emission source details, including stack parameters and proposed emission rates for individual GHGs and corresponding CO2e.

5.1 Steam Cracking Furnaces

The new cracker plant will incorporate eight steam cracking furnaces. Furnace GHG emissions from ethane cracking operations are detailed in Table A‐2 of Appendix A; GHG emissions from decoking operations appear in Table A‐3.

5.1.1 Normal Firing

Typically, the ethane steam cracking furnaces will combust plant tail gas (“fuel gas”); however, the furnaces may also operate on pipeline quality natural gas. To provide fuel flexibility, Chevron Phillips estimated annual GHG emissions from both fuel gas and natural gas firing and is proposing the that annual emissions for the furnaces be established at the maximum estimated PTE, as shown in Table A‐2, with fuel stream characteristics presented in Table A‐9.



Although maximum hourly fuel firing rates are represented in Table A‐2 for reference, annual emissions estimates for routine operations assume continuous operation at the expected annual average firing rate, 412 MMBtu/hr/furnace. Chevron Phillips expects that only seven furnaces will operate at a given time, since one furnace will be available for decoking and hot steam standby. Therefore, Chevron Phillips proposes to cap the annual PTE emissions contribution from all eight furnaces’ routine firing at a level consistent with annual operation of seven furnaces, plus decoking (as discussed in Section 5.1.2). Further, since steam generation from the furnaces is integrated with steam generation from the VHP boiler, the annual GHG emissions from the boiler, as discussed in Section 5.2, are included in this annual combustion unit emissions cap. In this way, although each individual furnace and the boiler may operate at each unit’s proposed annual emissions, the aggregate of the eight furnaces’ normal and decoking operations plus the boiler will not exceed the proposed combustion unit GHG emissions caps.

Chevron Phillips estimated the GHG emissions from the furnaces using EPA’s GHG reporting methodology as detailed in 40 CFR Part 98, Subpart X, §98.243(d) for ethylene production processes.

5.1.2 Decoke Operations

During routine decoking of the furnace tubes, carbon (coke) on the tubes is combusted to form primarily CO2 and a small amount of carbon monoxide (CO). To conservatively estimate GHGs from decoking operations, Chevron Phillips assumed 100% of the coke converts to CO2 during decoking. Although the furnaces are fired during decoke operations, firing is at a lower rate than the 412 MMBtu/hr basis used for annual fuel firing for each furnace. Therefore, fuel firing during decoke operations is already accounted for in the 8,760 hr/yr/furnace normal firing scenarios discussed in Section 5.1.1. Therefore, decoke GHG emissions estimates shown in Table A‐3 of Appendix A represent only the incremental GHGs generated during decoking from coke conversion to GHGs.

Although typical decoke cycles are approximately once every 50 days, more frequent coking may be required depending on actual operating conditions. Therefore, up to 12 decokes/yr/furnace were assumed in the decoking calculations.

5.2 VHP Boiler

Similar to the cracking furnaces, the VHP boiler may fire either natural gas or plant fuel gas. Therefore, Chevron Phillips estimated GHG emissions using both fuels, as shown in Table A‐4 of Appendix A, and is proposing the higher of the two annual rates to provide required fuel flexibility. Also, the boiler’s contribution to the annual GHG emissions cap from combustion devices is based on 720 hr/yr at the maximum firing rate (500 MMBtu/hr), 48 hr/yr in startup (at 500 MMBtu/hr), and the balance at the normal firing rate of 150 MMBtu/hr.



As discussed in Section 5.1.1, the interdependence of steam supply among the operation of the eight furnaces and the VHP boiler necessitates including the boiler’s annual GHG emissions in the overall combustion cap. In this way, the boiler may operate up to its proposed individual annual GHG emission rates in any given year, but aggregate GHG emissions from the boiler plus the furnaces will not exceed the proposed annual caps. Also, the boiler’s contribution to the annual GHG emissions cap from combustion devices is based on 720 hr/yr at the maximum firing rate (500 MMBtu/hr), 48 hr/yr in startup (at 500 MMBtu/hr), and the balance at the normal firing rate of 150 MMBtu/hr. Although these assumptions represent the basis for calculating the annual furnace/boiler emission caps, Chevron Phillips is not proposing specific limitations on boiler operating rates or schedule as long as compliance with the annual emission caps is demonstrated.

Because the boiler can fire plant fuel gas or natural gas, Chevron Phillips estimated GHG emissions from the VHP boiler consistent with the methodology used for the cracking furnaces: that for GHG reporting for ethylene processes as found in 40 CFR Part 98, Subpart X, §98.243(d).

5.3 Vapor Destruction Unit

The Vapor Destruction Unit (VDU) is used as a backup control device for process vent streams while maintenance or inspections are being performed on the VHP boiler. The VDU GHG emission calculations are based on the unit operating up to four weeks (672 hours) per year; however, longer boiler downtimes may occur as long as the allowable GHG emissions from sources authorized by this permit are not exceeded. For the remainder of the year, the VDU will remain on hot standby with only the pilots combusting fuel, which is the basis for calculating the remaining annual GHG emissions from the VDU.

As with the furnaces and the VHP boiler, Chevron Phillips estimated GHG emissions from the VDU using the methodology from 40 CFR Part 98, Subpart X, §98.243(d). Table A‐5 in Appendix A details the VDU GHG emissions estimates.

5.4 Low Profile Flare

The flare is a low profile flare is a safety device. The first stage is a low pressure burner that is steam‐assisted. The 14 remaining stages are high pressure burners that are unassisted. Table A‐6 in Appendix A details the GHG emissions estimates for this flare system.

Normal flaring operations control streams from vents that can be classified into three main types of activities: fugitive‐like sources such as “leak‐by” from safety relief and pressure control valves that are closed during routine operation, maintenance activities, and process adjustments to maintain product quality. These activities are expected to use the low pressure burner. The flow rate is based on measured values of a similar plant with adjustments for capacity and complexity.



Estimated emissions from the flare due to scheduled maintenance, start‐up and shutdown (MSS) activities are broken down by activity type. Maintenance flaring includes control of streams generated from maintenance performed on converters, dryers, filters, pumps, and exchangers. Start‐up flaring includes control of streams generated from startup activities in seven different sections of the facility. Shutdown stream flaring is assumed to be approximately one half of each of the start‐up streams.

For each flared stream, the total mass of vapors and the weight percent of each component were used to estimate stream properties and corresponding GHG emissions. The stream characteristics used for the flare GHG emissions basis are provided in Table A‐10 of Appendix A. Although these stream details are provided for emissions estimation purposes, speciation and total flow rates are based on process design as well as similar operating facilities' typical streams. Speciation and or flow volume may vary depending on process conditions and additional compounds similar to those represented may be present.

Natural gas‐fired pilots remain lit during normal operation to ensure the flare is available when needed. The flare has 30 pilots, each with a flow rate of 85 scfh.

GHG emissions estimates are based on natural gas firing for the pilots and petrochemical process vent firing for the balance of the flared stream. Therefore, 40 CFR Part 98, Subpart X, §98.243(d) is the appropriate emissions estimation methodology, which Chevron Phillips used for the flare.

5.5 Emergency Generators

Three diesel‐fired emergency generators will be located at the site with an aggregate power output of 4 MW. The generators will only operate during emergencies and on regularly scheduled intervals for testing. It is estimated that the generators will be operated a maximum of 52 hours per year each for testing. There will be no other emissions from the generator during normal operation.

GHG emissions from these diesel‐fired engines follow the approach for general combustion devices represented in 40 CFR Part 98, Subpart C and the emission factors for No. 2 distillate fuel represented in Tables C‐1 and C‐2 of Part 98. The resulting GHG emissions estimates are included in Table A‐7 of Appendix A.

5.6 Piping Fugitives

Table A‐8 of Appendix A details the fugitive emissions from piping components in fuel gas and natural gas piping in the new cracking unit. Fuel gas and natural gas both contain primarily methane, with additional heating value derived mostly from hydrogen (fuel gas) and ethane (natural gas). Other process streams in the cracker unit in volatile organic compound (VOC) service contain only insignificant quantities of GHGs as compared to other GHG sources in the cracker unit and therefore are not considered further in this application.



Although there are no established GHG piping fugitive emission factors, Chevron Phillips applied the average Synthetic Organic Chemical Manufacturing Industry (SOCMI) average emissions factors for petrochemical processes to the estimated fuel gas and natural gas piping component types and quantities to estimate fugitive total mass emissions from the fuel gas and natural gas piping in the cracking unit. Because many of these components may be in either natural gas or fuel gas service, and because natural gas is over 90% methane (a GHG), Chevron Phillips conservatively assumed 100% of the mass emissions were methane.

Date: 12/19/2011 Permit No.: To Be Determined Site Name: Cedar Bayou Plant

Company Name: Project:

New Ethylene Cracker Unit

(Unit 1594)

(A) EPN (B) FIN (C) NAME

CO2

CH4

N2O

CO2e

CO2

CH4

N2O

CO2e

CO2

CH4

N2O

CO2e

CO2

CH4

N2O

CO2e

Table 5‐1

Emission Point Summary

Chevron Phillips Chemical Company, LP

AIR CONTAMINANT DATA

1. Emission Point

2. Component or Air Contaminant Name 3. Air Contaminant Emission Rate (ton/yr)

206,000

1.2

0.2

Cracking Furnace 4

Cracking Furnace 2

H‐10100 H‐10100 Cracking Furnace 1

H‐10200 H‐10200

206,000

206,000

1.2

0.2

206,000


206,000

1.2

0.2

206,000

H‐10400 H‐10400

206,000

1.2

0.2

206,000

EPN = Emission Point NumberFIN = Facility Identification Number




(Unit 1594)


Table 5‐1




1. Emission Point


CO2

CH4

N2O

CO2e

CO2

CH4

N2O

CO2e

CO2

CH4

N2O

CO2e

CO2

CH4

N2O

CO2e


206,000


206,000

1.2

0.2

206,000


206,000

1.2

0.2

206,000

206,000

1.2

0.2

206,000


206,000

1.2

0.2





(Unit 1594)


Table 5‐1




1. Emission Point


CO2

CH4

N2O

CO2e

CO2

CH4

N2O

CO2e

CO2

CH4

N2O

CO2e

CO2

CH4

N2O

CO2e

0.04

27,000

1,100

B‐83010 B‐83010 VHP Boiler

127,000

0.6

0.1

127,000

2

1,572,000

PK‐90050 PK‐90050 Low Profile Flare

27,000

0.2

Furnace/Boiler Combustion Cap

1,572,000

9

PK‐90060 PK‐90060 Vapor Destruction Unit0.002

0.0002

1,100





(Unit 1594)


Table 5‐1




1. Emission Point


CO2

CH4

N2O

CO2e

CH4

CO2e

274

0.011

0.0022

275

PK‐87010A/B/C PK‐87010A Emergency Generators A/B/C

F‐1594 F‐1594 Process Fugitives324

6,800




6.0 BEST AVAILABLE CONTROL TECHNOLOGY ANALYSIS As required by 40 CFR §52.21(j),best available control technology (BACT) must be demonstrated for new and modified emissions sources in a PSD permit application for which a significant net emissions increase will occur. In this application, the only applicable pollutants are the GHGs CO2, CH4, N2O, and CO2e. For these pollutants, the following emissions sources propose significant net GHG emissions increases as defined by §52.21(b)(23)(ii) and §52.21(b)(49)(v):

Cracking furnaces,

VHP boiler,

Vapor destruction unit,

Low profile flare,

Routine emergency generator testing, and

Fugitive emissions from piping components in GHG service.

In its October 1990 draft guidance document entitled New Source Review Workshop Manual (Draft), EPA established a five‐step process for conducting a top‐down BACT review for PSD permitting. In its March 2011 guidance document for GHG permitting, PSD and Title V Permitting Guidance for Greenhouse Gases (EPA 457/B‐11‐001), EPA reaffirmed that this five‐step top‐down BACT analysis should also be used for GHG PSD permit application BACT demonstrations. Therefore, the five steps used in this BACT analysis are:

1. Identification of available control technologies;

2. Eliminate technically infeasible alternatives from further consideration;

3. Rank remaining technologies according to control effectiveness;

4. Evaluate the most effective controls from the standpoint of cost‐effectiveness, energy impacts, and environmental effects, continuing with the next most effective technology if unreasonable adverse impacts are identified for the more effective option(s); and

5. Select BACT.

As shown in Table A‐1, over 99.5% of the CO2e emissions proposed for the new cracker unit are CO2. With the exception of piping fugitives, CH4 and N2O contribute insignificantly to the overall GHG emissions potential, and even piping fugitives of CH4 contribute only 0.02% of the GHG mass emissions total and 0.4% of the CO2e total. Therefore, Chevron Phillips searched the EPA RACT/BACT/LAER Clearinghouse (RBLC) database only for applicable CO2 BACT determinations to assist in identifying potential GHG control technologies relevant to the proposed emissions sources. Appendix B of this application includes the corresponding RBLC search results.



6.1 Steam Cracking Furnaces

6.1.1 Step 1 – Identify Potential Control Technologies

For furnaces and boilers, the RBLC database identified only proper combustion operation and maintenance as BACT controls. Add‐on controls and other potential technologies have not been designated in the RBLC database as applicable GHG controls to date. Nonetheless, Chevron Phillips considered the following technologies as potential GHG control measures for the cracking furnaces in the new ethylene Unit 1594:

Carbon capture and storage (CCS),

Low‐carbon fuel(s),

Energy efficiencies, and

Good combustion practices and maintenance.

6.1.1.1 Carbon Capture and Storage

CCS requires separation of CO2 from flue gases, compression of the isolated CO2, transportation to a suitable injection/storage location, and long‐term storage in appropriate geologic formations. Although several technologies are available for segregating CO2 from moderate to high‐ CO2 purity flue gases, many of these are still being used on a pilot or laboratory scale and are not yet proven for use in large‐scale industrial applications except oil and gas production. Once segregated, the CO2 must be compressed and transported, requiring additional energy to accomplish. Geologic storage must consider the acidic nature of CO2 gases, especially in formations such as limestone that are susceptible to acidic erosion.

6.1.1.2 Low‐Carbon Fuel

Use of fuels containing lower concentrations of carbon generate less CO2 than other higher‐carbon fuels. Typically, gaseous fuels such as natural gas or high‐hydrogen plant tail gas contain less carbon, and thus lower CO2 potential, than liquid or solid fuels such as diesel or coal.

Chevron Phillips proposes to use high‐hydrogen plant tail gas as the primary fuel for the cracking furnaces. When this tail gas may be unavailable, the alternate fuel will be natural gas.

6.1.1.3 Energy Efficiency

Energy efficiency considers integration of heat and energy balances throughout a facility, not just for one piece of equipment. Therefore, energy efficiency is an integrated solution to plant‐wide energy optimization as compared to production.

Chevron Phillips proposes to use a proprietary furnace and integrated cold system design developed by its vendor to result in a lower carbon footprint than typical ethylene cracking process units. For example, the proprietary design recovers refrigeration capacity from



incoming ethane feed to reduce demand for refrigeration compression power downstream of the furnaces, resulting in reduced high‐pressure steam demand and thus reducing the required fuel combustion (and related CO2 generation) for steam generation. Lower pressure separation of ethylene and ethane likewise reduces compression and resulting steam demand and CO2 generation from combustion. The vendor also incorporates an optimized distillation tower design, resulting in minimization of reboiler and reflux demand, as well as proprietary optimized cooling water system design that that balances heat exchange temperatures with compression and circulation requirements. Further, excess high‐pressure steam is anticipated from incorporation of these energy efficiency measures. Thus, Chevron Phillips proposes to export this steam to other existing process units onsite, replacing and/or supplementing steam demand from older, less energy‐efficient existing steam generation units.

6.1.1.4 Good Combustion Practice

Good combustion practices include appropriate maintenance of equipment (such as periodic burner tune‐ups) and operating within the recommended combustion air and fuel ranges of the equipment as specified by its design, with the assistance of oxygen trim control. Although good combustion practices do not themselves necessarily directly reduce GHG emissions, using good combustion practices results in longer life of the equipment and more efficient operation. Therefore, such practices indirectly reduce GHG emissions by supporting operation as designed and with consideration of other energy optimization practices incorporated into the integrated plant.

Chevron Phillips will incorporate such combustion practices as recommended by its vendor and based on its extensive operating experience with steam cracking furnaces.

6.1.2 Step 2 – Eliminate Technically Infeasible Options


As indicated in its March 2011 PSD permitting guidance for GHGs, the EPA notes1:

For the purposes of a BACT analysis for GHGs, EPA classifies CCS as an add‐on pollution control technology that is “available” for facilities emitting CO2 in large amounts, including fossil fuel‐fired power plants, and for industrial facilities with high‐purity CO2 streams (e.g., hydrogen production, ammonia production, natural gas processing, ethanol production, ethylene oxide production, cement production, and iron and steel manufacturing). For these types of facilities, CCS should be listed in Step 1 of a top‐down BACT analysis for GHGs.

The new ethylene unit does not incorporate hydrogen recovery from the plant fuel gas, although the plant fuel gas is high in hydrogen content. However, rather than purify this

1 U.S. EPA, Office of Air Quality Planning and Standards, PSD and Title V Permitting Guidance for Greenhouse Gases, March 2011, p. 32.



hydrogen stream for sale, Chevron Phillips instead uses the high‐hydrogen/lower‐carbon tail gas stream as primary fuel for the furnaces, reducing the CO2 emissions from these large combustion units significantly from that which would be experienced if the hydrogen were recovered and sold and higher‐GHG fuels were used as primary furnace fuel year‐round.

Further, the furnace exhaust streams are not high‐purity streams, as recommended in EPA’s guidance. Instead, the furnace exhausts contain approximately 5% or less CO2 in the stack gas on an average annual basis. Therefore, the recovery and purification of CO2 from the stack gases would necessitate significant additional processing, including energy, and environmental/air quality penalties, to achieve the necessary CO2 concentration for effective sequestration.

Finally, even if the CO2 could be segregated efficiently from the furnace exhausts, the availability of appropriate sites for geologic sequestration in proximity to the facility does not exist. There are salt dome caverns within 10 to 15 miles of the site; however, these limestone formations have not been demonstrated to safely store acid gases such as CO2, nor is there adequate availability of space. Instead, these domes are used for cyclical storage of liquefied petroleum gases (LPGs) for use in the Gulf Coast as well as for shipment throughout the United States via pipeline. To replace this critical active storage with long‐term CO2 sequestration would necessarily jeopardize energy supplies locally and nationally. Other potential sequestration sites that are presently commercially viable, such as the SACROC enhanced oil recovery unit in the Permian Basin, are more than 400 to 500 miles from the proposed project site.

Further, as stated in the August 2010 Report of the Interagency Task on Carbon Capture and Storage2:

Current technologies could be used to capture CO2 from new and existing fossil energy power plants; however, they are not ready for widespread implementation primarily because they have not been demonstrated at the scale necessary to establish confidence for power plant application. Since the CO2 capture capacities used in current industrial processes are generally much smaller than the capacity required for the purposes of GHG emissions mitigation at a typical power plant, there is considerable uncertainty associated with capacities at volumes necessary for commercial deployment.

Therefore, because there is not a demonstrated commercial implementation of CCS for non‐power plant industrial applications, since the furnace stack gases are not high‐purity CO2 streams, and because there is not a viable geologic sequestration site available in the project area for long‐term CO2 storage, CCS is considered a technically infeasible control option for the

2 President Obama’s Interagency Task Force on Carbon Capture and Storage, Report of the Interagency Task Force on Carbon Capture and Storage, August 2010, p. 50.



proposed new cracking unit at Chevron Phillips’ Cedar Bayou plant and is not considered further in this analysis.


Use of low‐carbon fuel is considered technically feasible.


Use of certain energy efficiency measures is considered technically feasible.


Use of good combustion practices is considered technically feasible.

6.1.3 Step 3 – Rank According to Effectiveness

Since the remaining control measures identified in Section 6.1.1 – low‐carbon fuels, energy efficiency, and good combustion practices – are being proposed for this project, a ranking of the control technologies is not necessary for this application.

6.1.4 Step 4 – Evaluate the Most Effective Controls

Since Chevron Phillips proposes to incorporate the remaining control measures identified in Section 6.1.1, an evaluation of the energy, environmental, and economic impacts of the proposed measures is not necessary for this application.

6.1.5 Step 5 – Select BACT

Chevron Phillips proposes to incorporate low‐carbon fuels, energy efficiency, and good combustion practices discussed in Section 6.1.1 as BACT for controlling CO2 emissions from furnace combustion and its corresponding steam supply/demand as integrated with the process unit’s equipment downstream of the furnace.

6.2 Decoking Activities

Ethane cracking furnaces require periodic decoking to remove coke deposits from the furnace tubes. Coke buildup is unavoidable in olefin production in cracking furnaces, and removal of the same at optimal periods maintains the furnace at efficient ethane‐to‐ethylene conversion rates without increasing energy (fuel) demand. Decoking too early is unnecessary and results in excess shutdown/start‐up cycles; decoking too late results in fouled furnace tubes that reduce conversion rates and increases heat demand.


Decoking is the process of combusting the coke carbon on the tubes through the use of steam and air. Review of the RBLC database identified no specific BACT controls for GHG emissions from decoking operations. Limiting air in the decoking process would tend to drive the



conversion of coke to CO rather than CO2. Additionally, proper design and operation of the furnaces in accordance with manufacturer’s recommendations is important in managing the formation of coke in processing.


Although limiting air in the decoke process could reduce CO2 emissions, the result would be an increase in the CO emissions from this process. Since CO is likewise a criteria pollutant, controlling one pollutant category, GHGs, to the detriment of another, CO, is considered not beneficial and therefore is eliminated as technically infeasible.


The single option remaining for control of CO2 from decoking operations is to follow the design and operational parameters integrated into the furnace to limit the need for decoking and thus the corresponding CO2 emissions generated from the same. Therefore, ranking according to effectiveness is unnecessary.


The single option remaining for control of CO2 from decoking operations is to follow the design and operational parameters integrated into the furnace to limit the need for decoking and thus the corresponding CO2 emissions generated from the same. Therefore, further evaluation of this control method is unnecessary.


Chevron Phillips proposes to incorporate a combination of design and recommended operation to limit coke formation in the tubes to the extent practicable considering ethane as a raw material. Managing coke buildup through such methods will result in limited CO2 formation from annual decoking operations.

6.3 VHP Boiler

The VHP boiler is integrated in the energy balance of the entire new cracker plant and cannot be considered a stand‐along device from the standpoint of GHG control methods. This boiler is integral to the overall energy efficiency of the plant as discussed in Section 6.1. Further, the boiler serves not only to generate very high pressure steam, but also as the primary control device for low‐pressure process vents, obviating the need for a secondary combustion device such as the vapor destruction unit, which serves only the control function, to operate full‐time.


As with the cracking furnaces, the RBLC database identified only proper combustion operation and maintenance as BACT control for the VHP boiler or similar combustion devices. Add‐on controls and other potential technologies have not been designated in the RBLC database as



applicable GHG controls to date. Nonetheless, Chevron Phillips considered the following technologies as potential GHG control measures for the VHP boiler in the new ethylene Unit 1594:


Low‐carbon fuel(s),

Energy efficiencies, and


Each of these technologies is discussed in detail in Section 6.1.1 and therefore is not repeated here. The boiler will use low‐carbon natural gas as the primary fuel, with high‐hydrogen plant tail gas available as a second low‐carbon fuel, if needed. The energy efficiency measures integrated into the cracking plant as described for the furnaces also applies to the boiler, since it likewise is a contributor to the overall steam balance of the plant and must be considered as integrated in the overall plant energy efficient design. Finally, Chevron Phillips will operate the boiler in accordance with the vendor’s recommendations and Chevron Phillips’ experience for good combustion and maintenance practices.



For the reasons discussed in Section 6.1.2.1, CCS is likewise not a technically feasible option for GHG emissions control from the VHP boiler and therefore will not be considered further in this analysis.




Use of certain energy efficiency measures is considered technically feasible.




Since the remaining control measures identified in Section 6.3.1 – low‐carbon fuels, energy efficiency, and good combustion practices – are being proposed for this project, a ranking of the control technologies is not necessary for this application.






Chevron Phillips proposes to incorporate low‐carbon fuels, energy efficiency, and good combustion practices discussed in Section 6.3.1 as BACT for controlling CO2 emissions from boiler combustion and its corresponding steam supply/demand as integrated with the process unit’s equipment downstream of the boiler.

6.4 Vapor Destruction Unit

The VDU serves as a standby vent control system, which is not anticipated to operate (except in hot stand‐by/pilot‐only mode) more than four weeks each year, when the primary control device, the VHP boiler, may not be operational due to maintenance or inspection. The VDU is fueled by low‐carbon pipeline natural gas.


The RBLC database did not identify any GHG control technologies for control devices such as the VDU, particularly since the VDU is itself an add‐on control unit. Nonetheless, Chevron Phillips considered the following technologies as potential GHG control measures for VDU in the new ethylene Unit 1594:


Low‐carbon fuel, and



As discussed in Section 6.1.1.1, CCS requires separation of CO2 from flue gases, compression of the isolated CO2, transportation to a suitable injection/storage location, and long‐term storage in appropriate geologic formations.



Chevron Phillips proposes to use natural gas for the pilot gas during hot stand‐by mode and as supplemental fuel when the VDU controls low pressure vent streams. Liquid and solid fossil fuels are not proposed for use in the VDU.




Good combustion practices include appropriate maintenance of equipment (such as periodic burner tune‐ups) and operating within the recommended combustion air and fuel ranges of the equipment as specified by its design, with the assistance of oxygen trim control. Although good combustion practices do not themselves necessarily directly reduce GHG emissions, using good combustion practices results in longer life of the equipment and more efficient operation. Therefore, such practices indirectly reduce GHG emissions by supporting operation as designed and with consideration of other energy optimization practices incorporated into the integrated plant.

Chevron Phillips will incorporate such combustion practices as recommended by the VDU manufacturer.



As discussed in Section 6.1.2.1, CCS is technically impracticable in situations where stack gases have low concentrations and/or mass flow rates of CO2. Since the VDU’s typical hot stand‐by stack gas flow rate is less than 700 scf/hr at a CO2 concentration of 10% by volume (or less), carbon capture from this stream is technically impracticable. Likewise, there is not a viable geologic sequestration site available in the project area for long‐term CO2 storage. Therefore, CCS is considered a technically infeasible control option for the proposed VDU at Chevron Phillips’ Cedar Bayou plant and is not considered further in this analysis.






Since the remaining control measures identified in Section 6.4.1 – low‐carbon fuels and good combustion practices – are being proposed for this project, a ranking of the control technologies is not necessary for this application.






Chevron Phillips proposes to incorporate low‐carbon fuel and good combustion practices discussed in Section 6.4.1 as BACT for controlling CO2 emissions from the VDU.

6.5 Low Profile Flare

The low profile flare serves as a safety device designed to provide safe control of gases from the ethylene cracker and support units during periods of high pressure discharges during start‐up and shutdown, emergency situations, and other large volume maintenance clearing. Additionally, the flare may control some low‐pressure vent streams, such as “leak by” from safety relief and pressure control valves, sweep gas, and small volume maintenance activities. Similar to the VDU, the flare’s pilots are fueled by low‐carbon pipeline natural gas.


Similar to the VDU, the RBLC database did not identify any GHG control technologies for control devices such as the flare, particularly since the flare is itself an add‐on control unit. Nonetheless, Chevron Phillips considered the following technologies as potential GHG control measures for the low profile flare in the new ethylene Unit 1594:







Use of fuels containing lower concentrations of carbon generate less CO2 than other higher‐carbon fuels. Typically, gaseous fuels such as natural gas or high‐hydrogen plant tail gas contain less carbon, and thus lower CO2 potential, than liquid or solid fuels such as diesel or coal. Likewise, although flaring carbon‐containing vent streams (such as those in the ethylene unit that may contain methane) will necessarily result in CO2 formation, methane has a global warming potential 21 times higher than that of CO2. Therefore, control of such streams via flare to reduce methane emissions at the expense of CO2 generation results in lower overall CO2e emissions than leaving such streams uncontrolled.

Chevron Phillips proposes to use natural gas for the flare’s pilot gas and as supplemental fuel, if needed, to maintain appropriate vent stream heating value as required by applicable air quality regulations. Liquid and solid fossil fuels are not proposed for use with the flare.




Good combustion practices for flares include appropriate maintenance of equipment (such as periodic flare tip maintenance) and operating within the recommended heating value and flare tip velocity as specified by its design. Although good combustion practices do not themselves necessarily directly reduce GHG emissions, using good combustion practices results in longer life of the equipment and more efficient operation. Therefore, such practices indirectly reduce GHG emissions by supporting operation as designed and with consideration of other energy optimization practices incorporated into the integrated plant.

Chevron Phillips will incorporate such combustion practices as recommended by the flare manufacturer.



Flare exhaust, by design, cannot be captured for CO2 separation unless the flare is enclosed, which is a safety hazard for a large capacity flare required in an ethylene unit for safe handling of high pressure vent streams. Likewise, there is not a viable geologic sequestration site available in the project area for long‐term CO2 storage. Therefore, since flare exhaust cannot be captured and because a suitable storage facility is not available, CCS is considered a technically infeasible control option for the proposed low profile flare at Chevron Phillips’ Cedar Bayou plant and is not considered further in this analysis.






Since the remaining control measures identified in Section 6.5.1 – low‐carbon fuels and good combustion practices – are being proposed for this project, a ranking of the control technologies is not necessary for this application.






Chevron Phillips proposes to incorporate low‐carbon fuel and good combustion practices discussed in Section 6.5.1 as BACT for controlling CO2 emissions from the low profile flare.

6.6 Emergency Generators

The three emergency generator engines proposed for use in Unit 1594 normally will operate at a low annual capacity factor – only one hour per week (approximately 52 hrs/yr) – in non‐emergency use. The engines are designed to use diesel fuel, stored in onsite tanks, so that emergency power is available for safe shutdown of the facility in the event of a power outage that may also include natural gas supply curtailments.


Similar to other equipment previously discussed, the RBLC database did not identify any add‐on GHG control technologies emergency generator engines; only good combustion practices were identified in the RBLC as BACT for emergency generators. Nonetheless, Chevron Phillips considered the following technologies as potential GHG control measures for the emergency generators in the new ethylene Unit 1594:








Chevron Phillips proposes to use diesel fuel for the emergency generators, since non‐volatile fuel must be used for emergency operations.


Good combustion practices for compression ignition engines include appropriate maintenance of equipment (such as periodic testing as will be conducted weekly) and operating within the recommended air to fuel ratio recommended by the manufacturer. Although good combustion practices do not themselves necessarily directly reduce GHG emissions, using good combustion



practices results in longer life of the equipment and more efficient operation. Therefore, such practices indirectly reduce GHG emissions by supporting operation as designed and with consideration of other energy optimization practices incorporated into the integrated plant.

Chevron Phillips will incorporate such combustion practices as recommended by the generator manufacturer.



Because the emergency generators will normally operate 52 hours per year or less and because their stack gases are low in volume and CO2 mass rate, capture and segregation of CO2 for sequestration has not been demonstrated. Likewise, there is not a viable geologic sequestration site available in the project area for long‐term CO2 storage. Therefore, CCS is considered a technically infeasible control option for the proposed emergency generators at Chevron Phillips’ Cedar Bayou plant and is not considered further in this analysis.


Because the generators are intended for emergency use, these engines must be designed to use non‐volatile fuel such as diesel. Use of volatile (low‐carbon) natural gas or plant fuel gas in an emergency situation could exacerbate a potentially volatile environment that may be present under certain conditions, resulting in unsafe operation. Therefore, non‐volatile fuel is appropriate and necessary for emergency equipment. As a result, Chevron Phillips proposes diesel fuel for use in the emergency engines. The use of low‐carbon fuel is considered technically infeasible for emergency generator operation and is not considered further in this analysis.




Since the remaining control measure identified in Section 6.6.1 –good combustion practices – is being proposed for this project, a ranking of the control technology is not necessary for this application.


Since Chevron Phillips proposes to incorporate the remaining control measure identified in Section 6.6.1, an evaluation of the energy, environmental, and economic impacts of the proposed measure is not necessary for this application.




Chevron Phillips proposes to incorporate good combustion practices discussed in Section 6.6.1 as BACT for controlling CO2 emissions from the low profile flare. Further, these new engines will be subject to the federal New Source Performance Standard (NSPS) for Stationary Compression Ignition Internal Combustion Engines (40 CFR Part 60, Subpart IIII), such that specific emissions standards for various pollutants must be met during normal operation, such that the engines will meet or exceed BACT.

6.7 Piping Fugitives

GHGs from piping fugitives are generated primarily from plant fuel gas and natural gas lines within the cracker unit. Other process lines in VOC service contain an insignificant quantity of GHGs and therefore are not considered further in this evaluation. Lines containing nitrogen, instrument air, and other non‐fuel/non‐VOC fluids do not include GHGs and likewise are not evaluated further in this analysis.


Piping fugitives may be controlled by various techniques, including:

Use of leakless and/or sealless technology to eliminate fugitive emissions sources;

Implementation of instrument leak detection and repair (LDAR) programs as prescribed by various federal and state regulations and permit conditions;

Remote sensing using infrared cameras as an alternative to instrument LDAR programs; and

Implementation of audio/visual/olfactory (AVO) leak detection methods.


6.7.2.1 Leakless/Sealless Technology

Leakless technology valves may be incorporated in situations where highly toxic or otherwise hazardous materials are present. Likewise, some technologies, such as bellows valves, cannot be repaired without a unit shutdown. Because plant tail gas and natural gas are not considered highly toxic nor hazardous materials, these fluids do not warrant the risk of unit shutdown for repair and therefore leakless valve technology for fuel lines is considered technically impracticable.

Sealless pumps and compressors, or seal systems venting to a control device such as the VDU or flare, are technically feasible for fuel gas service. However, since the fuel gas‐specific piping lines systems in the proposed cracker plant do not include pumps or compressors, this technology is irrelevant and therefore considered technically impracticable.



6.7.2.2 Instrument LDAR Programs

Use of instrument LDAR is considered technically feasible.

6.7.2.3 Remote Sensing

Use of remote sensing measures is considered technically feasible.

6.7.2.4 AVO Monitoring

Use of as‐observed AVO monitoring is considered technically feasible. Use of scheduled AVO, such as that used for highly odorous compounds detectable by AVO methods in lower concentrations than would be detected by instrument LDAR and/or remote sensing, such as for high concentration mercaptan streams or those in hydrogen halide and/or halide service (e.g. H2S, chlorine) are not technically feasible for plant fuel gas or natural gas service.


Instrument LDAR programs and the alternative work practice of remote sensing using an infrared camera have been determined by EPA to be equivalent methods of piping fugitive controls.3

As‐observed AVO methods are generally somewhat less effective since they are not conducted at specified intervals. However, since pipeline natural gas is odorized with very small quantities of mercaptan, as‐observed olfactory observation is a very effective method for identifying and correcting leaks in natural gas systems. Due to the pressure and other physical properties of plant fuel gas, as‐observed audio and visual observations of potential fugitive leaks are likewise moderately effective.


Although instrument LDAR and/or remote sensing of piping fugitive emissions in fuel gas and/or natural gas service may be somewhat more effective than as‐observed AVO methods, the economic practicability of such programs cannot be verified. Specifically, fugitive emissions are estimates only, based on factors derived for a statistical sample and not specific to any single piping component nor specifically for fuel gas/natural gas service. Therefore, since the total contribution to the site’s CO2e PTE from piping fugitives is less than 0.4%, which is less than the statistical accuracy of the development of the factors themselves4, instrument LDAR programs or their equivalent alternative method, remote sensing, are not economically practicable controlling the piping fugitive GHGs emissions for this project.

As‐observed AVO is economically and environmentally practicable for this project.

3 73 FedReg 78199‐78219, December 22, 2008. 4 In Appendix B, Table B‐2‐2, of EPA’s Protocol for Equipment Leak Emissions Estimates (EPA 453/R‐95‐017), November 1995, the Agency considered only the upper and lower 95% confidence limits in developing revised SOCMI emission factors.




Chevron Phillips proposes to incorporate as‐observed AVO as BACT for the piping components in the new cracker plant in fuel gas and natural gas service.



7.0 OTHER PSD REQUIREMENTS

As identified in EPA’s GHG PSD permitting guidance document5, since there are no NAAQS or PSD increments for GHGs,126 the requirements in 40 CFR §2.21(k) and §51.166(k) of EPA’s regulations to demonstrate that a source does not cause or contribute to a violation of the NAAQS is not applicable to GHGs. Thus, EPA does not recommend nor require that PSD applicants model or conduct ambient monitoring for CO2 or GHGs.

Further, EPA believes it is not necessary for applicants or permitting authorities to assess impacts from GHGs in the context of the additional impacts analysis area provisions of the PSD regulations.

Based on the above guidance from EPA, Chevron Phillips is not required to nor is it including air dispersion modeling, ambient monitoring, or additional impacts analyses of GHGs specific to the new cracker unit on surrounding areas in this permit application.

5 U.S. EPA, Office of Air Quality Planning and Standards, PSD and Title V Permitting Guidance for Greenhouse Gases, March 2011, pp. 47‐48.


FINAL GHG Application 12.19.11.docx

APPENDIX A

Emissions Estimates

TABLE A-1Chevron Phillips Chemical Company LPCedar Bayou PlantGreenhouse Gas Emissions Summary

CO2 CH4 N2O CO2eH-10100 H-10100 Ethylene Steam Cracking Furnace 1 206,000 1.2 0.2 206,000H-10200 H-10200 Ethylene Steam Cracking Furnace 2 206,000 1.2 0.2 206,000H-10300 H-10300 Ethylene Steam Cracking Furnace 3 206,000 1.2 0.2 206,000H-10400 H-10400 Ethylene Steam Cracking Furnace 4 206,000 1.2 0.2 206,000H-10500 H-10500 Ethylene Steam Cracking Furnace 5 206,000 1.2 0.2 206,000H-10600 H-10600 Ethylene Steam Cracking Furnace 6 206,000 1.2 0.2 206,000H-10700 H-10700 Ethylene Steam Cracking Furnace 7 206,000 1.2 0.2 206,000H-10800 H-10800 Ethylene Steam Cracking Furnace 8 206,000 1.2 0.2 206,000H-10100 H-10100 Ethylene Steam Cracking Furnace 1 Decoke 362 362H-10200 H-10200 Ethylene Steam Cracking Furnace 2 Decoke 362 362H-10300 H-10300 Ethylene Steam Cracking Furnace 3 Decoke 362 362H-10400 H-10400 Ethylene Steam Cracking Furnace 4 Decoke 362 362H-10500 H-10500 Ethylene Steam Cracking Furnace 5 Decoke 362 362H-10600 H-10600 Ethylene Steam Cracking Furnace 6 Decoke 362 362H-10700 H-10700 Ethylene Steam Cracking Furnace 7 Decoke 362 362H-10800 H-10800 Ethylene Steam Cracking Furnace 8 Decoke 362 362B-83010 B-83010 VHP Boiler 127,000 0.6 0.1 127,000

Furnace/Boiler Cap 1 1,572,000 9.0 1.8 1,572,000PK-90060 PK-90060 Vapor Destruction Unit 1,100 0.002 0.0002 1,100PK-90050 PK-90050 Low Profile Flare 27,000 0.2 0.04 27,000

PK-87010A/B/C PK-87010A/B/C Emergency Generator Engines 274 0.011 0.002 275F-1594 F-1594 Process Fugitives 324 6,800

Totals: 1,600,000 333 2 1,607,000

Notes:1. Furnace/Boiler annual cap assumes an equivalent of 7 furnaces operating continuously at the annual emission rate, plus the average annual boiler emissions, plus all annual decoke (coke conversion) emissions for the 8 furnaces.

Annual (ton/yr)DescriptionFIN EPN

A-1Cracker GHG Emissions 12.19.11.xlsx

Summary

TABLE A-2Chevron Phillips Chemical Company LPCedar Bayou PlantGreenhouse Gas Emissions - Cracking Furnaces, Normal Operation

MMscf/hr2 MMscf/yr3 CH4 N2O CO25 CH46 N2O6 CO2e7

Natural Gas 1,029 0.49 3,508 0.741 16.64 0.0001 0.00001 206,000 0.4 0.04 206,000Fuel Gas 470 1.06 7,680 0.512 5.01 0.0003 0.00006 94,000 1.2 0.2 94,000

206,000 1.2 0.2 206,000Natural Gas 1,029 0.49 3,508 0.741 16.64 0.0001 0.00001 206,000 0.4 0.04 206,000

Fuel Gas 470 1.06 7,680 0.512 5.01 0.0003 0.00006 94,000 1.2 0.2 94,000206,000 1.2 0.2 206,000


206,000 1.2 0.2 206,000Natural Gas 1,029 0.49 3,508 0.741 16.64 0.0001 0.00001 206,000 0.4 0.04 206,000

Fuel Gas 470 1.06 7,680 0.512 5.01 0.0003 0.00006 94,000 1.2 0.2 94,000206,000 1.2 0.2 206,000


206,000 1.2 0.2 206,000Natural Gas 1,029 0.49 3,508 0.741 16.64 0.0001 0.00001 206,000 0.4 0.04 206,000

Fuel Gas 470 1.06 7,680 0.512 5.01 0.0003 0.00006 94,000 1.2 0.2 94,000206,000 1.2 0.2 206,000


206,000 1.2 0.2 206,000Natural Gas 1,029 0.49 3,508 0.741 16.64 0.0001 0.00001 206,000 0.4 0.04 206,000

Fuel Gas 470 1.06 7,680 0.512 5.01 0.0003 0.00006 94,000 1.2 0.2 94,000206,000 1.2 0.2 206,000

Annual Emissions, ton/yr

Ethylene Steam Cracking Furnace 7


H-10800 Ethylene Steam Cracking Furnace 8

500

500

500

500

500

500

500

500



H-10700


Fuel MW1

(kg/kg-mole)

Fuel Carbon

Content1

(kg C/kg fuel)

Fuel FlowFuelType

Maximum Firing Rate

(HHV)(MMBtu/hr)


Description

412

412

412

FIN


H-10300

Emission Factors4

(kg/MMBtu)

H-10100

72% Conversion Firing Rate

(HHV) (MMBtu/hr)

412

EPN

H-10100

H-10200

H-10300

Max:

Max:

Max:

412

412

412

412

Fuel HHV1

(Btu/scf)

Max:

Max:

Max:

Max:

Max:

H-10400

H-10500

H-10600

H-10700

H-10800


Furnaces-Normal

TABLE A-2Chevron Phillips Chemical Company LPCedar Bayou PlantGreenhouse Gas Emissions - Cracking Furnaces, Normal Operation

Notes:1. For fuel and natural gas heat, molecular weight, and carbon content data, refer toTable A-9 in this Appendix.

2. Based on maximum hourly firing rate (MMBtu/hr) / Fuel HHV (Btu/scf).For NG: MMScf/hr = 500 MMBtu/hr / 1,029 Btu/scf = 0.49 MMscf/hr

3. Estimated as: Specified Conversion Firing Rate (MMBtu/hr) / Fuel HHV (Btu/scf) * Annual Operation (hr/yr) * % of Annual Operation with this Fuel8,760 hr/yr annual operation used for annual emissions estimates.100% of annual operation using natural gas (to identify highest average annual PTE)

100% of annual operation using fuel gas (to identify highest average annual PTE)

For NG: MMScf/yr = 412 MMBtu/hr / 1,029 Btu/scf * 8,760 hr/yr * 100% of Annual Operation = 3,508 MMscf/yr

4. Factors for ethylene production processes designated in Table C-2 to Subpart C of 40 CFR Part 98 and 40 CFR §98.243(d)(3)(i).

5. CO2 emissions calculated in accordance with Equation C-5 of Subpart C of 40 CFR Part 98, adjusted to reflect ton/yr rather than metric tonne/yr:

CO2 = 44/12 * Fuel * CC * MW/MVC * 0.001 * 1.102 Where:

CO2 = Mass emissions of CO2, ton/yrFuel = Gaseous fuel volume, scf/yrCC = Annual average carbon content of the fuel, kg C/kg fuel

MW = Molecular weight of the fuel, kg/kg-moleMVC = Molar volume conversion at 68°F = 849.5 scf/kg-mole0.001 = Conversion from kg to metric tonne (0.001 tonne/kg)1.102 = Conversion from metric tonne to ton (1.102 ton/tonne)

For Furnace 1, Annual CO2 from Natural Gas Firing:CO2 = 44/12 * 3,507.58 MMscf/yr * 1,000,000 scf/MMscf * 0.741 kg C/kg fuel * 16.6 kg/kg-mole / 849.5 scf/kg-mole * 0.001 tonne/kg * 1.102 ton/tonne = 205,770 ton/yr CO2

6. CH4 and N2O emissions calculated in accordance with Equation C-8 to Subpart C of 40 CFR Part 98, adjusted to reflect ton/yr rather than metric tonne/yr:

CH4/N2O = 0.001 * Fuel * HHV * EF * 1.102

CH4/N2O = Mass emissions of CH4 or N2O, ton/yr0.001 = Conversion from kg to metric tonne (0.001 tonne/kg)Fuel = Gaseous fuel volume, scf/hr or scf/yrHHV = High heat value of fuel, MMBtu/scf

EF = Emission factor, kg/MMBtu1.102 = Conversion from metric tonne to ton (1.102 ton/tonne)

For Furnace 1, Annual CH4 from Natural Gas Firing:

CH4 = 0.001 tonne/kg * 3,507.58 MMscf/yr * 1,000,000 scf/MMscf * 1,029 Btu/scf * 1 MMBtu/1,000,000 Btu * 0.0001 kg/MMBtu *1.102 ton/tonne= 0.398 ton/yr CH4

7. CO2 equivalents (CO2e) calculated according to the following formula and conversions:

CO2e = ERi * GWPi

CO2e = Aggregate CO2 equivalent emissions for all greenhouse gases for this caseERi = Mass emission rate of greenhouse gas species "i"

GWPi = Greenhouse warming potential, as provided by Table A-1 to Subpart A of 40 CFR Part 98:CO2 GWP = 1CH4 GWP = 21N2O GWP = 310

For Furnace 1, Annual Natural Gas Combustion:CO2e = [ 206,000 ton/yr CO2 * 1 ton CO2e/ton CO2 ] + [ 0.40 ton/yr CH4 * 21 ton CO2e/ton CH4 ] + [ 0.040 ton/yr N2O * 310 ton CO2e/ton N2O ] = 206,021 ton/yr CO2e


Furnaces-Normal

TABLE A-3Chevron Phillips Chemical Company LPCedar Bayou PlantGreenhouse Gas Emissions - Cracking Furnaces, Decoke Mode (Coke Conversion)

CO2 CO2eH-10100 H-10100 16,460 12 100% 362 362H-10120 H-10120 16,460 12 100% 362 362H-10130 H-10130 16,460 12 100% 362 362H-10140 H-10140 16,460 12 100% 362 362H-10150 H-10150 16,460 12 100% 362 362H-10160 H-10160 16,460 12 100% 362 362H-10170 H-10170 16,460 12 100% 362 362H-10180 H-10180 16,460 12 100% 362 362

Notes:1. Coke estimates provided by furnce vendor.2. For conservative emissions estimation purposes only; actual number of decokes for each furnace may vary.3. Although not all coke carbon will convert to CO2, the majority is anticipated to do so and at times conversion may approach 90-100%. Therefore, for conservatism, 100% conversion to CO2 is assumed for purposes of GHG estimation.4. CO2 = lb C/decoke * # decokes/yr * 1 lbmol C/12 lb C * 1 lbmol CO2/1 lbmol C * 44 lb CO2/lbmol CO2 * % Conversion * 1 ton/2,000 lb For Furnace 1:

CO2 = 16,460 * 12 decokes/yr * 1 lbmol C/12 lb C * 1 lbmol CO2/1 lbmol C * 44 lb CO2/lbmol CO2 * 100% Conversion * 1 ton/2,000 lb = 362 ton/yr CO2



CO2e = 362 ton/yr CO2 * 1 ton CO2e/1 ton CO2 = 362 ton/yr CO2e

Annual Emissions4 (ton/yr)Max Conversion to

CO23 (%)FIN EPN lb C/decoke1 # decoke/yr2


Furnaces-Decoke

TABLE A-4Chevron Phillips Chemical Company LPCedar Bayou PlantGreenhouse Gas Emissions - Very High Pressure (VHP) Boiler


Natural Gas 1,029 0.49 1,538.27 0.741 16.64 0.0001 0.00001 90,000 0.17 0.017 90,000Fuel Gas 470 1.06 3,368.15 0.512 5.01 0.0003 0.00006 37,000 0.47 0.095 37,000

Total: 127,000 0.65 0.112 127,000

Notes:1. For fuel and natural gas heat, molecular weight, and carbon content data, refer to Table A-9 in this Appendix.


3. Estimated as: [ Max Rate (MMBtu/hr) / Fuel HHV (Btu/scf) * Annual Hrs at Max Rate (hr/yr) + Startup Rate (MMBtu/hr) / Fuel HHV (Btu/scf) * Annual Hrs at Startup Rate (hr/yr) + Normal Rate (MMBtu/hr) / Fuel HHV (Btu/scf) * Annual Hrs at Normal Rate (hr/yr) ] * % of Annual Operation with this Fuel720 hr/yr in maximum firing rate

48 hr/yr in startup firing rate7,992 hr/yr in normal firing rate100% of annual operation using natural gas (to identify highest average annual PTE)

100% of annual operation using fuel gas (to identify highest average annual PTE)

For NG: MMScf/yr = [ 500 MMBtu/hr / 1,029 Btu/scf * 720 hr/yr + 500 MMBtu/hr / 1,029 Btu/scf * 48 hr/yr + 150 MMBtu/hr / 1,029 Btu/scf * 7,992 hr/yr ] * 100% of Annual Operation with this Fuel = 1,538.27 MMscf/yr





MW = Molecular weight of the fuel, kg/kg-moleMVC = Molar volume conversion at 68°F = 849.5 scf/kg-mole

0.001 = Conversion from kg to metric tonne (0.001 tonne/kg)1.102 = Conversion from metric tonne to ton (1.102 ton/tonne)

For VHP Boiler, Annual CO2 from Natural Gas Firing:CO2 = 44/12 * 1,538.27 MMscf/yr * 1,000,000 scf/MMscf * 0.741 kg C/kg fuel * 16.6 kg/kg-mole / 849.5 scf/kg-mole * 0.001 kg/tonne * 1.102 ton/tonne = 90,242 ton/yr CO2

6. CH4 and N2O emissions calculated in accordance with Equation C-8 to Subpart C of 40 CFR Part 98:

CH4/N2O = 0.001 * Fuel * HHV * EF

0.001 = Conversion from kg to metric tonne (0.001 tonne/kg)CH4/N2O = Mass emissions of CH4 or N2O, metric tons (tonne)/hr or tonne/yr

Fuel = Gaseous fuel volume, scf/hr or scf/yrHHV = High heat value of fuel, MMBtu/scf


For VHP Boiler, Annual CH4 from Natural Gas Firing:

CH4 = 0.001 kg/tonne * 1,538.27 MMscf/yr * 1,000,000 scf/MMscf * 1,029 Btu/scf * 1 MMBtu/1,000,000 Btu * 0.0001 kg/MMBtu * 1.102 ton/tonne = 0.17 ton/yr CH4


CO2e = ERi * GWPi



For VHP Boiler, Annual Natural Gas Combustion:CO2e = [ 90,000 ton/yr CO2 * 1 ton CO2e/ton CO2 ] + [ 0.17 ton/yr CH4 * 21 ton CO2e/ton CH4 ] + [ 0.017 ton/yr N2O * 310 ton CO2e/ton N2O ] = 90,009 ton/yr CO2e

Startup Firing Rate (MMBtu/hr

B-83010 B-83010 VHP Boiler 500 500

FIN DescriptionMaximum

Firing Rate (MMBtu/hr)

EPN

150

Annual Emissions, ton/yrFuel

Carbon

Content1

(kg C/kg fuel)

Fuel MW1

(kg/kg-mole)

Emission Factors4

(kg/MMBtu)Fuel FlowNormal


FuelType

Fuel HHV1

(Btu/scf)


VHP Boiler

TABLE A-5Chevron Phillips Chemical Company LPCedar Bayou PlantGreenhouse Gas Emissions - Vapor Destruction Unit


Natural Gas 1,029 0.03 19.28 0.741 16.64 0.0001 0.00001 1,100 0.0022 0.00022 1,100Fuel Gas 470 0 0 0.512 5.01 0.0003 0.00006 0 0 0 0

Total: 1,100 0.002 0.0002 1,100

Notes:1. For fuel and natural gas heat, molecular weight, and carbon content data, refer to Table A-9 in this Appendix.


3. Estimated as: [ Max Rate (MMBtu/hr) / Fuel HHV (Btu/scf) * Annual Hrs at Max Rate (hr/yr) + Pilot Rate (MMBtu/hr) / Fuel HHV (Btu/scf) * Annual Hrs at Pilot Rate (hr/yr) ] * % of Annual Operation with this Fuel672 hr/yr in maximum firing rate

8,760 hr/yr in hot standby (pilot) firing rate100% of annual operation using natural gas

0% of annual operation using fuel gas

For NG: MMScf/yr = [ 28.8 MMBtu/hr / 1,029 Btu/scf * 672 hr/yr + 0.056 MMBtu/hr / 1,029 Btu/scf * 8,760 hr/yr ] * 100% of Annual Operation with this Fuel = 19.28 MMscf/yr







For VHP Boiler, Annual CO2 from Natural Gas Firing:CO2 = 44/12 * 19.28 MMscf/yr * 1,000,000 scf/MMscf * 0.741 kg C/kg fuel * 16.6 kg/kg-mole / 849.5 scf/kg-mole * 0.001 kg/tonne * 1.102 ton/tonne = 1,131 ton/yr CO2


CH4/N2O = 0.001 * Fuel * HHV * EF




For VHP Boiler, Annual CH4 from Natural Gas Firing:

CH4 = 0.001 kg/tonne * 19.28 MMscf/yr * 1,000,000 scf/MMscf * 1,029 Btu/scf * 1 MMBtu/1,000,000 Btu * 0.0001 kg/MMBtu * 1.102 ton/tonne = 0.00 ton/yr CH4


CO2e = ERi * GWPi




FIN EPN

PK-90060 PK-90060 Vapor Destruction Unit 28.8 0.056

DescriptionMaximum


Hot Standby (Pilot) Firing

Rate (MMBtu/hr)

Annual Emissions, ton/yrFuelType

Fuel HHV1

(Btu/scf)

Fuel FlowFuel

Carbon

Content1

(kg C/kg fuel)

Fuel MW1

(kg/kg-mole)

Emission Factors4

(kg/MMBtu)


VDU

TABLE A-6Chevron Phillips Chemical Company LPCedar Bayou PlantGreenhouse Gas Emissions - Low Profile Flare

CH4 N2O CO25 CH46 N2O6 CO2e7

Natural Gas Pilots 1,029 0.741 16.64 22 0.0001 0.00001 1,300 0.003 0.0003 1,300Startup Stream 1 1,803 0.799 30.26 755,351 9 0.0003 0.00006 1,100 0.006 0.0011 1,100Startup Stream 2 441 0.461 4.40 65,400 6 0.0003 0.00006 100 0.001 0.0002 100Startup Stream 3 1,446 0.782 26.03 229,934 3 0.0003 0.00006 300 0.002 0.0003 300Startup Stream 4 1,147 0.795 18.30 860,440 18 0.0003 0.00006 1,200 0.007 0.0014 1,200Startup Stream 5 1,688 0.834 28.94 378,768 5 0.0003 0.00006 600 0.003 0.0006 600Startup Stream 6 1,614 0.856 28.05 477,840 6 0.0003 0.00006 700 0.003 0.0007 700Startup Stream 7 2,334 0.856 42.08 84,956 1 0.0003 0.00006 100 0.001 0.0001 100

Shutdown Stream 1 1,029 0.74 16.64 377,676 9 0.0003 0.00006 500 0.003 0.0006 500Shutdown Stream 2 1,803 0.80 30.26 32,700 0 0.0003 0.00006 0 0.0002 0.00005 0Shutdown Stream 3 441 0.46 4.40 114,967 10 0.0003 0.00006 100 0.001 0.0003 100Shutdown Stream 4 1,446 0.78 26.03 430,220 6 0.0003 0.00006 600 0.003 0.0006 600Shutdown Stream 5 1,147 0.79 18.30 189,384 4 0.0003 0.00006 300 0.001 0.0003 300Shutdown Stream 6 1,688 0.83 28.94 238,920 3 0.0003 0.00006 400 0.002 0.0003 400Shutdown Stream 7 1,614 0.86 28.05 42,478 1 0.0003 0.00006 100 0.000 0.0001 100

Routine Vents 454 0.301 11.44 33,857,614 1,124 0.0003 0.00006 18,400 0.17 0.034 18,400Maintenance Stream 1 748 0.723 10.86 635,654 22 0.0003 0.00006 800 0.005 0.0011 800Maintenance Stream 2 1,870 0.829 32.40 26,797 0 0.0003 0.00006 40 0.0002 0.00004 40Maintenance Stream 3 2,271 0.841 40.20 9,562 0 0.0003 0.00006 10 0.0001 0.00001 10Maintenance Stream 4 2,334 0.851 41.80 6,699 0 0.0003 0.00006 10 0.00005 0.00001 10Maintenance Stream 5 1,479 0.836 26.04 19,268 0 0.0003 0.00006 30 0.0001 0.00003 30

Total: 27,000 0.2 0.04 27,000

Molar Volume: 379.5 scf/lbmol @60 °F

Low Profile FlarePK-90050PK-90050

Annual Emissions, ton/yrFIN EPN Description

Stream

Flow2

(lb/yr)

Stream

Flow3

(MMscf/yr)

FuelType

Fuel HHV1

(Btu/scf)

Fuel Carbon

Content1

(kg C/kg fuel)

Fuel MW1

(kg/kg-mole)

Emission Factors4

(kg/MMBtu)


Flare

TABLE A-6Chevron Phillips Chemical Company LPCedar Bayou PlantGreenhouse Gas Emissions - Low Profile Flare

Notes:1. For natural gas heat value, molecular weight and carbon content data, refer to Table A-9 in this Appendix. For startup, maintenance, and routine vent streams, refer to Table A-10 in this Appendix. Shutdown streams are estimated to have approximately the same composition as startup streams.

Speciation and flow rates may vary depending on process conditions, and additional compounds and/or flow rates similar to those represented may be present.

2. Flow rates for startup, routine vents, and maintence streams are based on monitoring data from a similar existing flare. Shutdown stream rates are estimated at one-half that of corresponding startup streams.

3. For natural gas pilots: MMscf/yr = # pilots * flow/pilot (scfh) * 8,760 hr/yr * MMscf/1,000,000 scfPilots (MMscf/yr) = 30 pilots *39:3985 scfh/pilot * 8,760 hr/yr * MMscf/1,000,000 scf = 22 MMscf/yr

For Vent Streams: MMscf/yr = Mass Rate (lb/yr) / MW (lb/lbmol) * Molar Volume (379.5 scf/lbmol) * MMscf/1,000,000 scfFor Startup 1 = 755,351 lb/yr / 30.26 lb/lbmol * 379.5 scf/lbmol * MMscf/1,000,000 scf = 9 MMscf/yr







For Pilots, Annual CO2 from Natural Gas Firing:CO2 = 44/12 * 22 MMscf/yr * 1,000,000 scf/MMscf * 0.741 kg C/kg fuel * 16.6 kg/kg-mole / 849.5 scf/kg-mole * 0.001 kg/tonne * 1.102 ton/tonne = 1,310 ton/yr CO2


CH4/N2O = 0.001 * Fuel * HHV * EF




For Pilots, Annual CH4 from Natural Gas Firing:

CH4 = 0.001 kg/tonne * 22 MMscf/yr * 1,000,000 scf/MMscf * 1,029 Btu/scf * 1 MMBtu/1,000,000 Btu * 0.0001 kg/MMBtu * 1.102 ton/tonne = 0.003 ton/yr CH4


CO2e = ERi * GWPi





Flare

TABLE A-7Chevron Phillips Chemical Company LPCedar Bayou PlantGreenhouse Gas Emissions - Emergency Generators

hr/test test/week hr/yr MMBtu/yr1 CO2 CH4 N2O CO23 CH43 N2O3 CO2e4

PK-87010A PK-87010A Emergency Generator 1 1.35 95% 45% No. 2 Diesel 1.00 1 104 1,122 73.96 0.003 0.0006 91 0.004 0.0007 92PK-87010B PK-87010B Emergency Generator 2 1.35 95% 45% No. 2 Diesel 1.00 1 104 1,122 73.96 0.003 0.0006 91 0.004 0.0007 92PK-87010C PK-87010C Emergency Generator 3 1.35 95% 45% No. 2 Diesel 1.00 1 104 1,122 73.96 0.003 0.0006 91 0.004 0.0007 92

Total: 274 0.011 0.0022 275Notes:1. Fuel Use = Power Output (MW) / Generator Efficiency (%) / Fuel Efficiency (%) * Conversion Factor (3,415,179 Btu/hr-MW) * Annual Operation (hr/yr) * MMBtu/1,000,000 Btu

For PK-87010A: MMBtu/yr = 1.35 MW / 95% / 45% * 3,415,179 Btu/hr-MW * 104 hr/yr * MMBtu/1,000,000 Btu = 1,122 MMBtu/yr

2. Factors for general stationary fuel combustion from 40 CFR Part 98, Subpart C, Tables C-1 and C-2.

3. CO2, CH4 and N2O emissions calculated from 40 CFR Part 98, Chapter C emission factors and annual fuel use:

CO2/CH4/N2O = Fuel (MMBtu/yr) * EF (kg/MMBtu) * 2.2 lb/kg * 1 ton/2,000 lb

For PK-87010A, Annual CO2 from No. 2 Diesel Firing:

CO2 = 73.96 kg/MMBtu * 1,122 MMBtu/yr * 2.2 lb/kg *28:281 ton/2,000 lb = 91 ton/yr CO2


CO2e = ERi * GWPi



For PK-87010A, Annual CO2e from No. 2 Diesel Firing:CO2e = [ 91 ton/yr CO2 * 1 ton CO2e/ton CO2 ] + [ 0.004 ton/yr CH4 * 21 ton CO2e/ton CH4 ] + [ 0.0007 ton/yr N2O * 310 ton CO2e/ton N2O ] = 92 ton/yr CO2e

Emission Factors2

(kg/MMBtu)Fuel Use Annual Emissions, ton/yrOperation

FIN EPN DescriptionPower Output (MW)

Generator Efficiency

(%)

FuelType

Fuel Efficiency

(%)


Emergency Generators

TABLE A-8Chevron Phillips Chemical Company LPCedar Bayou PlantGreenhouse Gas Emissions - Piping Fugitives

Total Piping Fugitive Emissions:

Valves Flanges Connectors Valves Flanges ConnectorsF-1594 F-1594 Process Fugitives FG/NG 2,800 8,700 800 0.0132 0.0039 0.0039 324

Speciated GHG Piping Fugitive Emissions:

F-1594 F-1594 Process Fugitives CH4 100% 324 6,800

Notes:1. FG = Fuel Gas; NG = Natural Gas.

2. SOCMI Average Factors, based on EPA-453/R-95-017, November 1995, Page 2-12.

3. Total Estimated Emissions:ET (ton/yr) = ( [Count(i) * Factor (i)] ) * 8,760 hr/yr * 1 ton/2,000 lb

ET (ton/yr) = ( [(2,800 * 0.0132) + (8,700 * 0.0039) + (800 * 0.0039)] * 8,760 hr/yr * 1 ton/2,000 lb = 324 ton/yr

4. For purposes of emissions estimation only, conservatively assumes stream could be 100% GHG (methane) in natural gas. Actual speciation may differ in GHG content.

5. Consistuent Emissions:EGHGi (ton/yr) = ET (ton/yr) * GHGi wt%

For CH4, EGHGi (ton/yr) = 324 ton/yr total * 100% = 324 ton/yr CH4


CO2e = ERi * GWPi



For CH4 ECO2e (ton/yr) = 324 ton/yr CH4 * 21 GWP = 6,807 ton/yr CO2e

Estimated

Emissions3, ton/yr

FIN Description GHG

Maximum

wt%4

GHG Mass

Emissions5, ton/yr

CO2e

Emissions6, ton/yr

Component CountsFIN Description Service1

Emission Factors2 (lb/hr/component)EPN

EPN


Fugitives

TABLE A-9Chevron Phillips Chemical Company LPCedar Bayou PlantGreenhouse Gas Emissions - Fuel Stream Characteristics

Fuel Gas (FG) =Wt%*100 =kg/MW =kgmol/kgmol*100 =Mol% * MW =wt%*Carbon Content =Mol% * HHV =Btu/mol / MolVol

kg kgmole Mol%2

Nitrogen N2 28.013 0 0 0.11 0.11 0.004 0.02 0.005 0 0 0Hydrogen H2 2.016 0 123,364 32.04 32.040 15.89 78.98 1.59 0 97,436 256.7Methane CH4 16.043 0.749 384,517 66.90 66.900 4.17 20.72 3.32 0.501 79,686 210.0Ethylene C2H4 28.054 0.856 612,645 0.16 0.160 0.006 0.03 0.008 0.001 174 0.5Ethane C2H6 30.069 0.799 680,211 0.54 0.540 0.018 0.09 0.027 0.004 607 1.6Propane C3H8 44.096 0.817 983,117 0.16 0.160 0.004 0.02 0.008 0.001 177 0.5Butane C4H10 58.123 0.827 1,279,191 0.04 0.040 0.001 0.003 0.002 0.000 44 0.1Butylene C4H8 56.100 0.856 1,170,631 0.03 0.030 0.001 0.003 0.001 0.000 31 0.1Pentane C5H12 72.150 0.832 1,524,401 0.03 0.030 0.000 0.002 0.001 0.000 32 0.1Hexane C6H14 86.170 0.836 1,804,940 0.02 0.020 0.000 0.001 0.001 0.000 21 0.1Carbon Monoxide CO 28.010 0.429 122,225 0.61 0.610 0.022 0.11 0.030 0.003 132 0.3Carbon Dioxide CO2 44.010 0.273 0 0.19 0.190 0.004 0.02 0.009 0.001 0 0

Totals: 100.8 100.8 20.12 100.00 5.01 0.512 178,339 469.9

Natural Gas (NG) =Wt%*100 =kg/MW =kgmol/kgmol*100 =Mol% * MW =wt%*Carbon Content =Mol% * HHV =Btu/mol / MolVol

kg kgmole Mol%2

Nitrogen N2 28.013 0 0 0.67 0.67 0.02 0.40 0.11 0 0 0Methane CH4 16.043 0.749 384,517 93.37 93.37 5.82 96.87 15.54 0.699 372,464 981.5Ethane C2H6 30.069 0.799 680,211 3.23 3.23 0.11 1.79 0.54 0.026 12,161 32.0Propane C3H8 44.096 0.817 983,117 0.93 0.93 0.02 0.35 0.15 0.008 3,451 9.1Butane C4H10 58.123 0.827 1,279,191 0.21 0.21 0.004 0.06 0.03 0.002 769 2.0Butylene C4H8 56.100 0.856 1,170,631 0.20 0.20 0.004 0.06 0.03 0.002 695 1.8Pentane C5H12 72.150 0.832 1,524,401 0.17 0.17 0.002 0.04 0.03 0.001 598 1.6Hexane C6H14 86.170 0.836 1,804,940 0.10 0.10 0.001 0.02 0.02 0.001 349 0.9Carbon Dioxide CO2 44.010 0.273 0 1.11 1.11 0.03 0.42 0.18 0.003 0 0

Totals: 100.0 100.0 6.01 100.0 16.64 0.741 390,486 1,028.9Molar Volume: 379.5 scf/lbmol @60 °F

NOTE:Speciation is based on process design as well as similar operating facilities' typical streams. Speciation may vary depending on process conditions and additional compounds similar to those represented may be present.

Basis = 100 kg FG MW Contribution3

(kg/kgmol NG)Carbon Contribution4

(kg C/kg NG)HHV Contribution6

(Btu/scf NG)

HHV Contribution5

(Btu/lbmol FG)

HHV Contribution5

(Btu/lbmol NG)

Basis = 100 kg FG MW Contribution3

(kg/kgmol FG)Carbon Contribution4

(kg C/kg FG)HHV Contribution6

(Btu/scf FG)

Wt%

Constituent FormulaMW

(kg/kgmol)Carbon Content1

(kg C/kg Constituent)High Heat Value

(HHV) (Btu/lbmol) Wt%



(kg C/kg Constituent)

High Heat Value

(HHV)2 (Btu/lbmol)


Stream Character (Fuels)

TABLE A-9Chevron Phillips Chemical Company LPCedar Bayou PlantGreenhouse Gas Emissions - Fuel Stream Characteristics


Notes:1. Constituent Carbon Content = (No. C molecules * MW C) / MW Constituent

For methane: C = (1 C molecule * 12.01 kg/kgmol C) / 16.04 kg/kg/mol methane = 0.749 kg C/kg Constituent

2. Mole % calculated on a basis of 100 kg of the constituent:kgmoli = Wt%i * 100 / MWi (kg/kgmol)

For FG methane: kgmoli = 66.90% * 100 / 16.043 kg/kgmol methane = 4.17 kgmol

Mol%i = (kgmoli / kgmoli) * 100For FG methane: Mol%i = 4.17 kgmol / 20.12 kgmol total * 100 = 20.72 Mol%

3. Molecular Weight Contribution based on Mole % of the Constituent * MW of ConstituentMW Contribi = Mol%i * MWi (kg/kgmol)

For FG methane: MW Contribi = 20.72 Mol% * 16.043 kg/kgmol methane = 3.32 kg/kgmol FG

MW Stream = MW Contributioni (kg/kgmol)

4. Carbon Content Contribution based on Wt% of the Consituent * C Content of Constituent:C Content Contribi = Wt%i * C Contenti (kg C/kg Constituent)

For FG methane: C Content Contribi = 66.90 Wt% * 0.749 kg C/kg methane) = 0.501 kg C/kg FG

C Content Stream = C Content Contributioni (kg C/kg Stream)

5. HHVContribution based on Mole % of the Consituent * HHV of Constituent:HHV Contributioni = Mol%i * HHVi (Btu/lbmol Constituent)

For FG methane: HHV Contributioni = 20.72 Mol% * 384,517 Btu/lbmol methane = 79,686 Btu/lbmol FG

HHV Stream = HHV Contributioni (Btu/lbmol Stream)

6. HHV Contribution, Btu/scf:

HHV Contributioni = HHV Contributioni (Btu/lbmol Constituent) / Molar Volume (scf/lbmol)

For FG methane: HHV Contributioni = 79,686 Btu/lbmol methane / 379.5 scf/lmol @60F = 210.0 Btu/scf methane

HHV Stream = HHV Contributioni (Btu/scf Stream)


Stream Character (Fuels)

TABLE A-10Chevron Phillips Chemical Company LPCedar Bayou PlantGreenhouse Gas Emissions - Flared Stream Characteristics

Startup Stream 1 (SU-1) =Wt%*100 =kg/MW =kgmol/kgmol*100 =Mol% * MW =wt%*Carbon Content =Mol% * HHV =Btu/mol / MolVol

kg kgmole Mol%2

Methane CH4 16.043 0.749 384,517 0.70 0.70 0.04 1.32 0.21 0.005 5,077 13.4Ethane C2H6 30.069 0.799 680,211 95.40 95.40 3.17 96.00 28.87 0.762 653,026 1,720.8Propane C3H8 44.096 0.817 983,117 3.90 3.90 0.088 2.68 1.18 0.032 26,310 69.3Hydrogen Sulfide H2S 34.070 0.000 241,749 0.00003 0.00003 0.000001 0.00003 0.00001 0 0.1 0.0002

Totals: 100.0 100.0 3.30 100.00 30.26 0.799 684,413 1,803.5


kg kgmole Mol%2

Hydrogen H2 2.016 0 123,364 38.10 38.10 18.90 83.13 1.68 0 102,555 270.2Methane CH4 16.043 0.749 384,517 61.00 61.00 3.80 16.73 2.68 0.457 64,312 169.5Ethylene C2H4 28.054 0.856 612,645 0.19 0.19 0.007 0.03 0.008 0.002 183 0.5Carbon Monoxide CO 28.010 0.429 122,225 0.72 0.72 0.026 0.11 0.032 0.003 138 0.364

Totals: 100.0 100.0 22.73 100.00 4.40 0.461 167,187 440.5


kg kgmole Mol%2

Hydrogen H2 2.016 0 123,364 1.10 1.10 0.55 14.21 0.29 0 17,529 46.2Methane CH4 16.043 0.749 384,517 2.30 2.30 0.14 3.73 0.60 0.017 14,355 37.8Acetylene C2H2 26.020 0.923 558,890 0.10 0.10 0.00 0.10 0.03 0.001 559 1.5Ethylene C2H4 28.054 0.856 612,645 37.80 37.80 1.35 35.09 9.84 0.324 214,963 566.4Ethane C2H6 30.069 0.799 680,211 25.30 25.30 0.84 21.91 6.59 0.202 149,040 392.7Propylene C3H6 42.080 0.856 885,601 26.60 26.60 0.63 16.46 6.93 0.228 145,781 384.1Propane C3H8 44.096 0.817 983,117 0.20 0.20 0.005 0.12 0.052 0.002 1,161 3.1Butadienes C4H6 54.090 0.888 1,093,340 0.40 0.40 0.007 0.19 0.10 0.004 2,106 5.5Butylene C4H8 56.100 0.856 1,170,631 0.05 0.050 0.001 0.023 0.013 0.000 272 0.7Cyclohexane C6H12 84.160 0.856 1,700,767 0.07 0.070 0.001 0.022 0.018 0.001 368 1.0Pentane C5H12 72.150 0.832 1,524,401 0.10 0.10 0.001 0.036 0.026 0.001 550 1.4Benzene C6H6 78.112 0.923 1,420,051 0.20 0.20 0.003 0.067 0.052 0.002 947 2.5Hexane C6H14 86.170 0.976 1,804,940 0.02 0.020 0.0002 0.006 0.005 0.000 109 0.3Toluene C7H8 92.138 0.782 1,698,187 0.04 0.040 0.0004 0.011 0.010 0.000 192 0.5Xylenes C8H10 106.165 0.905 1,976,436 0.024 0.024 0.0002 0.006 0.006 0.000 116 0.3Nonene C9H18 126.240 0.856 2,397,550 0.10 0.100 0.001 0.021 0.026 0.001 495 1.3Carbon Monoxide CO 28.010 0.429 122,225 0.02 0.020 0.001 0.02 0.005 0.000 23 0.1Carbon Dioxide CO2 44.010 0.273 0 0.03 0.030 0.001 0.02 0.008 0.000 0 0.0Hydrogen Sulfide H2S 34.070 0.000 241,749 0.003 0.003 0.0001 0.00 0.001 0.000 6 0.015Water H2O 18.000 0.000 0 5.5 5.50 0.31 7.96 1.432 0.000 0 0.000

Totals: 100.0 100.0 3.84 100.00 26.03 0.782 548,572 1,445.5





HHV Contribution6

(Btu/scf SU-3)Constituent FormulaMW




Basis = 100 kg SU-3 MW Contribution3

(kg/kgmol SU-3)Carbon Contribution4

(kg C/kg SU-3)







(kg C/kg SU-1)


HHV Contribution5

(Btu/lbmol SU-1)HHV Contribution6

(Btu/scf SU-1)

MW Contribution3


(kg C/kg SU-2)HHV Contribution5


(Btu/scf SU-2)

HHV Contribution5

(Btu/lbmol SU-3)

Basis = 100 kg SU-2


Stream Character (Flaring)




kg kgmole Mol%2

Hydrogen H2 2.016 0 123,364 3.90 3.90 1.93 35.40 0.71 0 43,672 115.1Methane CH4 16.043 0.749 384,517 7.50 7.50 0.47 8.55 1.37 0.056 32,895 86.7Ethylene C2H4 28.054 0.856 612,645 53.00 53.00 1.89 34.57 9.70 0.454 211,802 558.1Ethane C2H6 30.069 0.799 680,211 34.50 34.50 1.15 21.00 6.31 0.276 142,818 376.3Propylene C3H6 42.080 0.856 885,601 1.00 1.00 0.024 0.43 0.18 0.009 3,851 10.1Propane C3H8 44.096 0.817 983,117 0.10 0.10 0.002 0.04 0.018 0.001 408 1.1

Totals: 100.0 100.0 5.46 100.00 18.30 0.795 435,446 1,147.4


kg kgmole Mol%2

Ethylene C2H4 28.054 0.856 612,645 59.60 59.60 2.12 61.42 17.23 0.510 376,299 991.6Ethane C2H6 30.069 0.799 680,211 39.20 39.20 1.30 37.69 11.33 0.313 256,379 675.6Propylene C3H6 42.080 0.856 885,601 1.10 1.10 0.026 0.76 0.32 0.009 6,693 17.6Propane C3H8 44.096 0.817 983,117 0.20 0.20 0.005 0.13 0.058 0.002 1,289 3.4

Totals: 100.1 100.1 3.46 100.00 28.94 0.834 640,660 1,688.2


kg kgmole Mol%2

Ethylene C2H4 28.054 0.856 612,645 100.00 100.00 3.56 100.00 28.05 0.856 612,645 1,614.3Totals: 100.0 100.0 3.56 100.00 28.05 0.856 612,645 1,614.3


kg kgmole Mol%2

Propylene C3H6 42.080 0.856 885,601 100.00 100.00 2.38 100.00 42.08 0.856 885,601 2,333.6Totals: 100.0 100.0 2.38 100.00 42.08 0.856 885,601 2,333.6




(HHV) (Btu/lbmol)HHV Contribution6

(Btu/scf SU-4)

Constituent




(Btu/lbmol SU-4)

MW (kg/kgmol)

Carbon Content1






(Btu/lbmol SU-5)

Wt%

HHV Contribution6

(Btu/scf SU-5)

HHV Contribution5

(Btu/lbmol SU-6)Constituent FormulaMW




(Btu/scf SU-6)









(Btu/scf SU-7)

Wt%



(kg C/kg SU-6)

Formula





Routine Vent Stream Average Annual (RV) =Wt%*100 =kg/MW =kgmol/kgmol*100 =Mol% * MW =wt%*Carbon Content =Mol% * HHV =Btu/mol / MolVol

kg kgmole Mol%2

Nitrogen N2 28.013 0 0 50.92 50.92 1.82 20.785 5.82 0 0 0Hydrogen H2 2.016 0 123,364 9.88 9.88 4.90 56.04 1.13 0 69,130 182.2Methane CH4 16.043 0.749 384,517 27.84 27.84 1.74 19.84 3.18 0.208 76,298 201.0Acetylene C2H2 26.020 0.923 558,890 0.02 0.020 0.00 0.01 0.00 0.000 49 0.1Ethylene C2H4 28.054 0.856 612,645 1.48 1.48 0.053 0.60 0.17 0.013 3,696 9.7Ethane C2H6 30.069 0.799 680,211 2.62 2.62 0.087 1.00 0.30 0.021 6,777 17.9Propylene C3H6 42.080 0.856 885,601 3.24 3.24 0.077 0.88 0.37 0.028 7,797 20.5Propane C3H8 44.096 0.817 983,117 1.02 1.02 0.023 0.26 0.12 0.008 2,600 6.9Butadienes C4H6 54.090 0.888 1,093,340 0.12 0.12 0.002 0.03 0.014 0.001 277 0.7Butylene C4H8 56.100 0.856 1,170,631 0.16 0.16 0.003 0.033 0.018 0.001 382 1.0Butane C4H10 58.123 0.827 1,279,191 0.52 0.52 0.009 0.102 0.059 0.004 1,309 3.4Pentane C5H12 72.150 0.832 1,524,401 0.05 0.050 0.001 0.008 0.006 0.000 121 0.3Pentenes C5H10 70.133 0.856 1,452,233 1.64 1.64 0.023 0.267 0.19 0.014 3,883 10.2Hexane C6H14 86.170 0.976 1,804,940 0.03 0.03 0.000 0.004 0.003 0.000 72 0.2Carbon Monoxide CO 28.010 0.429 122,225 0.14 0.14 0.005 0.06 0.016 0.001 70 0.2Carbon Dioxide CO2 44.010 0.273 0 0.33 0.33 0.007 0.09 0.038 0.001 0 0

Totals: 100.0 100.0 8.75 100.00 11.44 0.301 172,460 454.4

Maintenance Stream 1 (M-1) =Wt%*100 =kg/MW =kgmol/kgmol*100 =Mol% * MW =wt%*Carbon Content =Mol% * HHV =Btu/mol / MolVol

kg kgmole Mol%2

Hydrogen H2 2.016 0 123,364 16.70 16.70 8.28 89.93 1.81 0 110,946 292.3Methane CH4 16.043 0.749 384,517 0.74 0.74 0.05 0.50 0.08 0.006 1,926 5.1Propylene C3H6 42.080 0.856 885,601 0.61 0.61 0.014 0.16 0.066 0.005 1,394 3.7Propane C3H8 44.096 0.817 983,117 0.16 0.16 0.004 0.04 0.017 0.001 387 1.0Butadienes C4H6 54.090 0.888 1,093,340 0.30 0.30 0.006 0.06 0.033 0.003 658 1.7Butylene C4H8 56.100 0.856 1,170,631 0.05 0.050 0.001 0.010 0.005 0.000 113 0.3Butane C4H10 58.123 0.827 1,279,191 0.01 0.010 0.000 0.002 0.001 0.000 24 0.1Pentane C5H12 72.150 0.832 1,524,401 4.60 4.60 0.064 0.692 0.50 0.038 10,552 27.8Pentenes C5H10 70.133 0.856 1,452,233 6.13 6.13 0.087 0.949 0.67 0.052 13,781 36.3Isoprene C5H8 68.117 0.882 1,384,540 4.60 4.60 0.068 0.733 0.50 0.041 10,151 26.7Hexenes C6H12 84.160 0.856 1,732,620 0.43 0.43 0.005 0.055 0.047 0.004 961 2.5Benzene C6H6 78.112 0.923 1,420,051 12.96 12.96 0.17 1.801 1.41 0.120 25,579 67.4Hexane C6H14 86.170 0.976 1,804,940 0.14 0.140 0.002 0.018 0.015 0.001 318 0.8Toluene C7H8 92.138 0.782 1,698,187 8.23 8.230 0.089 0.970 0.89 0.064 16,468 43.4Xylenes C8H10 106.165 0.905 1,976,436 15.70 15.70 0.15 1.606 1.70 0.142 31,732 83.6Nonene C9H18 126.240 0.856 2,397,550 28.62 28.62 0.23 2.461 3.11 0.245 59,012 155.5Carbon Monoxide CO 28.010 0.429 122,225 0.03 0.03 0.00 0.01 0.003 0.000 14 0.0

Totals: 100.0 100.0 9.21 100.00 10.86 0.723 284,016 748.4

MW (kg/kgmol)

Carbon Content1



(Btu/scf M-1)Wt%

Basis = 100 kg M-1 MW Contribution3

(kg/kgmol M-1)Carbon Contribution4

(kg C/kg M-1)HHV Contribution5

(Btu/lbmol M-1)Constituent Formula





Basis = 100 kg RV MW Contribution3

(kg/kgmol RV)Carbon Contribution4

(kg C/kg RV)HHV Contribution5

(Btu/lbmol V)HHV Contribution6

(Btu/scf RV)






kg kgmole Mol%2

Methane CH4 16.043 0.749 384,517 15.13 15.13 0.94 30.56 4.90 0.113 117,491 309.6Ethylene C2H4 28.054 0.856 612,645 9.55 9.55 0.34 11.03 3.09 0.082 67,570 178.0Ethane C2H6 30.069 0.799 680,211 4.17 4.17 0.14 4.49 1.35 0.033 30,563 80.5Propylene C3H6 42.080 0.856 885,601 48.97 48.97 1.16 37.70 15.87 0.419 333,909 879.9Propane C3H8 44.096 0.817 983,117 21.99 21.99 0.50 16.16 7.12 0.180 158,842 418.6Xylenes C8H10 106.165 0.905 1,976,436 0.20 0.20 0.00 0.061 0.065 0.002 1,206 3.2

Totals: 100.0 100.0 3.09 100.00 32.40 0.829 709,581 1,869.8


kg kgmole Mol%2

Nitrogen N2 28.013 0 0 0.02 0.02 0.00 0.029 0.008 0.000 0 0.0Hydrogen H2 2.016 0 123,364 0.53 0.53 0.26 10.57 0.21 0 13,036 34.4Methane CH4 16.043 0.749 384,517 4.16 4.16 0.26 10.42 1.67 0.031 40,078 105.6Ethylene C2H4 28.054 0.856 612,645 16.75 16.75 0.60 24.00 6.73 0.143 147,031 387.4Ethane C2H6 30.069 0.799 680,211 3.62 3.62 0.12 4.84 1.46 0.029 32,917 86.7Propylene C3H6 42.080 0.856 885,601 16.58 16.58 0.39 15.84 6.66 0.142 140,258 369.6Propane C3H8 44.096 0.817 983,117 5.43 5.43 0.12 4.95 2.18 0.044 48,662 128.2Butadienes C4H6 54.090 0.888 1,093,340 0.63 0.63 0.01 0.47 0.25 0.006 5,119 13.5Butylene C4H8 56.100 0.856 1,170,631 0.54 0.54 0.01 0.387 0.22 0.005 4,529 11.9Butane C4H10 58.123 0.827 1,279,191 15.96 15.96 0.27 11.037 6.42 0.132 141,189 372.0Pentane C5H12 72.150 0.832 1,524,401 4.98 4.98 0.07 2.774 2.00 0.041 42,293 111.4Pentenes C5H10 70.133 0.856 1,452,233 6.64 6.64 0.09 3.806 2.67 0.057 55,267 145.6Isoprene C5H8 68.117 0.882 1,384,540 4.98 4.98 0.07 2.939 2.00 0.044 40,687 107.2Hexenes C6H12 84.160 0.856 1,732,620 5.99 5.99 0.07 2.861 2.41 0.051 49,568 130.6Benzene C6H6 78.112 0.923 1,420,051 2.10 2.10 0.03 1.081 0.84 0.019 15,346 40.4Hexane C6H14 86.170 0.976 1,804,940 2.00 2.00 0.02 0.933 0.80 0.020 16,839 44.4Toluene C7H8 92.138 0.782 1,698,187 1.22 1.22 0.01 0.532 0.49 0.010 9,038 23.8Xylenes C8H10 106.165 0.905 1,976,436 0.270 0.27 0.00 0.102 0.11 0.002 2,020 5.3Nonene C9H18 126.240 0.856 2,397,550 7.61 7.61 0.06 2.423 3.06 0.065 58,095 153.1Hydrogen Sulfide H2S 34.070 0.000 241,749 0.010 0.01 0.00 0.01 0.004 0.000 29 0.075

Totals: 100.0 100.0 2.49 100.00 40.20 0.841 862,002 2,271.4

High Heat Value (HHV) (Btu/lbmol)

HHV Contribution6

(Btu/scf M-3)Wt%




(Btu/lbmol M-3)Constituent FormulaMW


(kg C/kg Constituent)








(Btu/lbmol M-2)HHV Contribution6

(Btu/scf M-2)






kg kgmole Mol%2

Methane CH4 16.043 0.749 384,517 0.04 0.04 0.00 0.10 0.02 0.000 401 1.1Ethylene C2H4 28.054 0.856 612,645 19.34 19.34 0.69 28.81 8.08 0.166 176,522 465.1Ethane C2H6 30.069 0.799 680,211 1.17 1.17 0.04 1.63 0.49 0.009 11,062 29.1Propylene C3H6 42.080 0.856 885,601 41.09 41.09 0.98 40.81 17.17 0.352 361,432 952.4Propane C3H8 44.096 0.817 983,117 20.27 20.27 0.46 19.21 8.47 0.166 188,881 497.7Butadienes C4H6 54.090 0.888 1,093,340 1.21 1.21 0.02 0.93 0.51 0.011 10,222 26.9Butylene C4H8 56.100 0.856 1,170,631 1.06 1.06 0.02 0.790 0.44 0.009 9,245 24.4Butane C4H10 58.123 0.827 1,279,191 1.25 1.25 0.02 0.899 0.52 0.010 11,498 30.3Pentane C5H12 72.150 0.832 1,524,401 1.16 1.16 0.02 0.672 0.48 0.010 10,244 27.0Pentenes C5H10 70.133 0.856 1,452,233 1.55 1.55 0.02 0.924 0.65 0.013 13,414 35.3Isoprene C5H8 68.117 0.882 1,384,540 1.16 1.16 0.02 0.712 0.48 0.010 9,855 26.0Hexenes C6H12 84.160 0.856 1,732,620 0.08 0.08 0.00 0.040 0.033 0.001 688 1.8Benzene C6H6 78.112 0.923 1,420,051 2.02 2.02 0.03 1.081 0.84 0.019 15,348 40.4Hexane C6H14 86.170 0.976 1,804,940 0.03 0.03 0.00 0.015 0.013 0.000 263 0.7Toluene C7H8 92.138 0.782 1,698,187 1.10 1.10 0.01 0.499 0.46 0.009 8,474 22.3Xylenes C8H10 106.165 0.905 1,976,436 6.290 6.29 0.06 2.476 2.63 0.057 48,942 129.0Nonene C9H18 126.240 0.856 2,397,550 1.18 1.18 0.01 0.391 0.49 0.010 9,367 24.7

Totals: 100.0 100.0 2.39 100.00 41.80 0.851 885,856 2,334.3


kg kgmole Mol%2

Hydrogen H2 2.016 0 123,364 0.35 0.35 0.17 4.52 0.09 0 5,577 14.7Methane CH4 16.043 0.749 384,517 0.73 0.73 0.05 1.18 0.19 0.005 4,556 12.0Ethylene C2H4 28.054 0.856 612,645 1.57 1.57 0.06 1.46 0.41 0.013 8,928 23.5Ethane C2H6 30.069 0.799 680,211 17.44 17.44 0.58 15.10 4.54 0.139 102,738 270.7Propylene C3H6 42.080 0.856 885,601 24.44 24.44 0.58 15.12 6.36 0.209 133,943 352.9Propane C3H8 44.096 0.817 983,117 13.49 13.49 0.31 7.97 3.51 0.110 78,321 206.4Butadienes C4H6 54.090 0.888 1,093,340 4.20 4.20 0.08 2.02 1.09 0.037 22,108 58.3Butylene C4H8 56.100 0.856 1,170,631 1.91 1.91 0.03 0.887 0.50 0.016 10,379 27.3Butane C4H10 58.123 0.827 1,279,191 16.19 16.19 0.28 7.254 4.22 0.134 92,788 244.5Pentane C5H12 72.150 0.832 1,524,401 3.18 3.18 0.04 1.148 0.83 0.026 17,496 46.1Pentenes C5H10 70.133 0.856 1,452,233 4.24 4.24 0.06 1.574 1.10 0.036 22,863 60.2Isoprene C5H8 68.117 0.882 1,384,540 3.21 3.21 0.05 1.227 0.84 0.028 16,991 44.8Hexenes C6H12 84.160 0.856 1,732,620 0.63 0.63 0.01 0.195 0.16 0.005 3,378 8.9Benzene C6H6 78.112 0.923 1,420,051 3.14 3.14 0.04 1.047 0.82 0.029 14,865 39.2Hexane C6H14 86.170 0.976 1,804,940 0.31 0.31 0.00 0.094 0.081 0.003 1,691 4.5Toluene C7H8 92.138 0.782 1,698,187 0.37 0.37 0.00 0.105 0.096 0.003 1,776 4.7Xylenes C8H10 106.165 0.905 1,976,436 0.130 0.13 0.00 0.032 0.034 0.001 630 1.7Nonene C9H18 126.240 0.856 2,397,550 4.48 4.48 0.04 0.924 1.17 0.038 22,157 58.4

Totals: 100.0 100.0 2.38 61.87 26.04 0.836 561,185 1,478.7

HHV Contribution6

(Btu/scf M-5)Wt%




(Btu/lbmol M-5)Constituent FormulaMW



(HHV) (Btu/lbmol)








(Btu/lbmol M-4)HHV Contribution6

(Btu/scf M-4)





Molar Volume: 379.5 scf/lbmol @60 °F

Notes:1. Constituent Carbon Content = (No. C molecules * MW C) / MW Constituent

For methane: C = (1 C molecule * 12.01 kg/kgmol C) / 16.04 kg/kg/mol methane = 0.749 kg C/kg Constituent

2. Mole % calculated on a basis of 100 kg of the constituent:kgmoli = Wt%i * 100 / MWi (kg/kgmol)

For FG methane: kgmoli = 0.70% * 100 / 16.043 kg/kgmol methane = 0.04 kgmol

Mol%i = (kgmoli / kgmoli) * 100For FG methane: Mol%i = 0.04 kgmol / 3.30 kgmol total * 100 = 1.32 Mol%

3. Molecular Weight Contribution based on Mole % of the Constituent * MW of ConstituentMW Contribi = Mol%i * MWi (kg/kgmol)

For FG methane: MW Contribi = 1.32 Mol% * 16.043 kg/kgmol methane = 0.21 kg/kgmol FG

MW Stream = MW Contributioni (kg/kgmol)

4. Carbon Content Contribution based on Wt% of the Consituent * C Content of Constituent:C Content Contribi = Wt%i * C Contenti (kg C/kg Constituent)

For FG methane: C Content Contribi = 0.70 Wt% * 0.749 kg C/kg methane) = 0.005 kg C/kg FG

C Content Stream = C Content Contributioni (kg C/kg Stream)

5. HHVContribution based on Mole % of the Consituent * HHV of Constituent:HHV Contributioni = Mol%i * HHVi (Btu/lbmol Constituent)

For FG methane: HHV Contributioni = 1.32 Mol% * 384,517 Btu/lbmol methane = 5,077 Btu/lbmol FG

HHV Stream = HHV Contributioni (Btu/lbmol Stream)

6. HHV Contribution, Btu/scf:

HHV Contributioni = HHV Contributioni (Btu/lbmol Constituent) / Molar Volume (scf/lbmol)

For FG methane: HHV Contributioni = 5,077 Btu/lbmol methane / 379.5 scf/lmol @60F = 13.4 Btu/scf methane

HHV Stream = HHV Contributioni (Btu/scf Stream)




FINAL GHG Application 12.19.11.docx

APPENDIX B

RACT/BACT/LAER Clearinghouse Search Results

COMPREHENSIVE REPORTReport Date:12/11/2011

Facility Information

RBLC ID: LA-0254 (draft) DateDeterminationLast Updated: 11/07/2011

Corporate/CompanyName:

ENTERGY LOUISIANA LLC PermitNumber:

PSD-LA-752

Facility Name: NINEMILE POINT ELECTRIC GENERATING PLANT Permit Date: 08/16/2011(actual)

Facility Contact: CHRISTEE HERBERT (504) 576-5699 [email protected] FRS Number: 110002049328

Facility Description: 1827 MW POWER PLANT (PRE-PROJECT). NATURAL GAS IS PRIMARY FUEL; NO. 2 & NO. 4 FUELOIL ARE SECONDARY FUELS. PROJECT INVOLVES DECOMMISSIONING OF 2 BOILERS AND THECONSTRUCTION OF 2 COMBINED CYCLE GAS TURBINES WITH DUCT BURNERS, A NATURALGAS-FIRED AUXILIARY BOILER, A DIESEL GENERATOR, 2 COOLING TOWERS, A FUEL OILSTORAGE TANK, A DIESEL-FIRED FIREWASTER PUMP, AND AN ANHYDROUS AMMONIA TANK.FUELS FOR THE TURBINES INCLUDE NATURAL GAS, NO. 2 FUEL OIL, AND ULTRA LOW SULFURDIESEL.

SIC Code: 4911

Permit Type: B: Add new process to existing facility NAICS Code: 221112

Permit URL: EPA Region: 6 COUNTRY: USA

Facility County: JEFFERSON

Facility State: LA

Facility ZIP Code: 70094

Permit Issued By: LOUISIANA DEPARTMENT OF ENV QUALITY (Agency Name) MR. KEITH JORDAN(Agency Contact) (225)219-3613 [email protected]

Other AgencyContact Info:

PERMIT WRITER: CHRIS SMITH, (225) 219-3417

Permit Notes: APPLICATION ACCEPTED RECEIVED DATE = DATE OF ADMINISTRATIVE COMPLETENESS BACT FOR GREENHOUSE GASES(CO2E) FROM THE COMBINED CYCLE TURBINE GENERATORS (UNITS 6A & 6B) IS OPERATING PROPERLY AND PERFORMINGNECESSARY ROUTINE MAINTENANCE, REPAIR, AND REPLACEMENT TO MAINTAIN THE GROSS HEAT RATE AT OR BELOW7630 BTU/KW-HR (HHV) (ANNUAL AVERAGE).

Process/Pollutant Information

PROCESS COMBINED CYCLE TURBINE GENERATORS (UNITS 6A & 6B)

PROCESSNAME:

COMBINED CYCLE TURBINE GENERATORS (UNITS 6A & 6B)

Process Type: 15.200 (Combined Cycle & Cogeneration (>25 MW))

Primary Fuel: NATURAL GAS

Throughput: 7146.00 MM BTU/HR

Process Notes: TURBINES ALSO PERMITTED TO BURN NO. 2 FUEL OIL AND ULTRA LOW SULFUR DIESEL. FUEL OIL USE IS LIMITED TO 1000HOURS PER YEAR.

POLLUTANT NAME: Particulate matter, total < 2.5 µ (TPM2.5)

CAS Number: PMTest Method: OtherOther Test Method: METHOD 201APollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 26.2300 LB/HR HOURLY AVERAGE W/O DUCT BURNEREmission Limit 2: 33.1600 LB/HR HOURLY AVERAGE W/ DUCT BURNERStandard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: OPERATING PERMIT Control Method: (P) WHILE FIRING NATURAL GAS: USE OF PIPELINE QUALITY NATURAL GAS AND GOOD

COMBUSTION PRACTICES WHILE FIRING FUEL OIL: USE OF ULTRA LOW SULFUR FUEL OIL ANDGOOD COMBUSTION PRACTICES

Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: WHILE FIRING FUEL OIL, THE BACT LIMIT FOR PM2.5 IS 36.37 LB/HR (HOURLY AVERAGE) BACT

FOR GREENHOUSE GASES (CO2E) FROM THE COMBINED CYCLE TURBINE GENERATORS (UNITS6A & 6B) IS OPERATING PROPERLY AND PERFORMING NECESSARY ROUTINE MAINTENANCE,REPAIR, AND REPLACEMENT TO MAINTAIN THE GROSS HEAT RATE AT OR BELOW 7630BTU/KW-HR (HHV) (ANNUAL AVERAGE).

POLLUTANT NAME: Particulate matter, total < 10 µ (TPM10)

CAS Number: PMTest Method: EPA/OAR Mthd 201A and 202Pollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 26.2300 LB/HR HOURLY AVERAGE W/O DUCT BURNEREmission Limit 2: 33.1600 LB/HR HOURLY AVERAGE W/ DUCT BURNER

Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: OPERATING PERMIT Control Method: (P) WHILE FIRING NATURAL GAS: USE OF PIPELINE QUALITY NATURAL GAS AND GOOD

COMBUSTION PRACTICES WHILE FIRING FUEL OIL: USE OF ULTRA LOW SULFUR FUEL OIL ANDGOOD COMBUSTION PRACTICES

Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: WHILE FIRING FUEL OIL, THE BACT LIMIT FOR PM10 IS 36.37 LB/HR (HOURLY AVERAGE) BACT

FOR GREENHOUSE GASES (CO2E) FROM THE COMBINED CYCLE TURBINE GENERATORS (UNITS6A & 6B) IS OPERATING PROPERLY AND PERFORMING NECESSARY ROUTINE MAINTENANCE,REPAIR, AND REPLACEMENT TO MAINTAIN THE GROSS HEAT RATE AT OR BELOW 7630BTU/KW-HR (HHV) (ANNUAL AVERAGE).

POLLUTANT NAME: Carbon Monoxide

CAS Number: 630-08-0Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds ) Emission Limit 1: Emission Limit 2: Standard Emission: 3.0000 PPMVD @ 15% O2 HOURLY AVERAGEDid factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: OPERATING PERMIT Control Method: (B) OXIDATION CATALYST AND GOOD COMBUSTION PRACTICESEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: CO MONITORED USING CEMS. 3 PPMVD @ 15% O2 LIMIT APPLIES WHEN OPERATING W/ AND

W/O THE DUCT BURNER AND WHEN FIRING FUEL OIL. STARTUP/SHUTDOWN: PROGRESSTHROUGH THE SU/SD EVENT AS QUICKLY AS POSSIBLE WHILE FOLLOWING THEMANUFACTURER'S RECOMMENDED PROCEDURES. SU/SD OPERATIONS LIMITED TO 1302HR/YR. BACT FOR GREENHOUSE GASES (CO2E) FROM THE COMBINED CYCLE TURBINEGENERATORS (UNITS 6A & 6B) IS OPERATING PROPERLY AND PERFORMING NECESSARYROUTINE MAINTENANCE, REPAIR, AND REPLACEMENT TO MAINTAIN THE GROSS HEAT RATEAT OR BELOW 7630 BTU/KW-HR (HHV) (ANNUAL AVERAGE).

POLLUTANT NAME: Volatile Organic Compounds (VOC)

CAS Number: VOCTest Method: EPA/OAR Mthd 25APollutant Group(s): ( Volatile Organic Compounds (VOC) ) Emission Limit 1: 1.4000 PPMVD @ 15% O2 HOURLY AVERAGE W/O DUCT BURNEREmission Limit 2: 3.8000 PPMVD @ 15% O2 HOURLY AVERAGE W/ DUCT BURNERStandard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: OPERATING PERMIT Control Method: (P) GOOD COMBUSTION PRACTICESEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: WHILE FIRING FUEL OIL, THE BACT LIMIT FOR VOC IS 3.1 PPMVD @ 15% O2 (HOURLY

AVERAGE) STARTUP/SHUTDOWN: PROGRESS THROUGH THE SU/SD EVENT AS QUICKLY ASPOSSIBLE WHILE FOLLOWING THE MANUFACTURER'S RECOMMENDED PROCEDURES. SU/SDOPERATIONS LIMITED TO 1302 HR/YR. BACT FOR GREENHOUSE GASES (CO2E) FROM THECOMBINED CYCLE TURBINE GENERATORS (UNITS 6A & 6B) IS OPERATING PROPERLY ANDPERFORMING NECESSARY ROUTINE MAINTENANCE, REPAIR, AND REPLACEMENT TOMAINTAIN THE GROSS HEAT RATE AT OR BELOW 7630 BTU/KW-HR (HHV) (ANNUAL AVERAGE).


PROCESS NAME: AUXILIARY BOILER (AUX-1)

Process Type: 11.310 (Natural Gas (includes propane and liquefied petroleum gas))


Throughput: 338.00 MM BTU/HR

Process Notes:


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: Emission Limit 2: Standard Emission: 7.6000 LB/MM SCF ANNUAL AVERAGE

Standard Emission: 7.6000 LB/MM SCF ANNUAL AVERAGEDid factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: OPERATING PERMIT Control Method: (P) USE OF PIPELINE QUALITY NATURAL GAS AND GOOD COMBUSTION PRACTICESEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: Emission Limit 2: Standard Emission: 7.6000 LB/MM SCF ANNUAL AVERAGEDid factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: OPERATING PERMIT Control Method: (P) USE OF PIPELINE QUALITY NATURAL GAS AND GOOD COMBUSTION PRACTICESEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: 630-08-0Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds ) Emission Limit 1: Emission Limit 2: Standard Emission: 84.0000 LB/MM SCF ANNUAL AVERAGEDid factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: OPERATING PERMIT

Control Method: (P) USE OF PIPELINE QUALITY NATURAL GAS AND GOOD COMBUSTION PRACTICESEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: VOCTest Method: UnspecifiedPollutant Group(s): ( Volatile Organic Compounds (VOC) ) Emission Limit 1: Emission Limit 2: Standard Emission: 5.5000 LB/MM SCF ANNUAL AVERAGEDid factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: OPERATING PERMIT Control Method: (P) USE OF PIPELINE QUALITY NATURAL GAS AND GOOD COMBUSTION PRACTICESEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:

POLLUTANT NAME: Carbon Dioxide

CAS Number: 124-38-9Test Method: UnspecifiedPollutant Group(s): ( Acid Gasses/Mist , Greenhouse Gasses (GHG) , InOrganic Compounds ) Emission Limit 1: Emission Limit 2: Standard Emission: 117.0000 LB/MM BTU Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: OPERATING PERMIT Control Method: (P) PROPER OPERATION AND GOOD COMBUSTION PRACTICESEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:

POLLUTANT NAME: Methane

CAS Number: 74-82-8Test Method: UnspecifiedPollutant Group(s): ( Greenhouse Gasses (GHG) , Organic Compounds (all) , Organic Non-HAP Compounds ) Emission Limit 1: Emission Limit 2: Standard Emission: 0.0022 LB/MM BTU Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: OPERATING PERMIT Control Method: (P) PROPER OPERATION AND GOOD COMBUSTION PRACTICESEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:

POLLUTANT NAME: Nitrous Oxide (N2O)

CAS Number: 10024-97-2Test Method: UnspecifiedPollutant Group(s): ( Greenhouse Gasses (GHG) , InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) ) Emission Limit 1: Emission Limit 2: Standard Emission: 0.0002 LB/MM BTU Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: OPERATING PERMIT Control Method: (P) PROPER OPERATION AND GOOD COMBUSTION PRACTICESEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


PROCESS NAME: CHILLER COOLING TOWER (CHILL CT)

PROCESS NAME: CHILLER COOLING TOWER (CHILL CT)

Process Type: 99.009 (Industrial Process Cooling Towers)

Primary Fuel: Throughput: 12000.00 GALS/MIN

Process Notes:


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: Emission Limit 2: Standard Emission: 0.0010 PERCENT DRIFT ANNUAL AVERAGEDid factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: OPERATING PERMIT Control Method: (P) HIGH EFFICIENCY MIST ELIMINATOREst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: MASS EMISSION RATES ARE NOT ESTABLISHED BY THE PSD PERMIT.


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: Emission Limit 2: Standard Emission: 0.0010 PERCENT DRIFT ANNUAL AVERAGEDid factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: OPERATING PERMIT Control Method: (P) HIGH EFFICIENCY MIST ELIMINATOREst. % Efficiency:Compliance Verified: Unknown

Pollutant/Compliance Notes: MASS EMISSION RATES ARE NOT ESTABLISHED BY THE PSD PERMIT.


PROCESS NAME: UNIT 6 COOLING TOWER


Primary Fuel: Throughput: 115847.00 GALS/MIN

Process Notes:


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: Emission Limit 2: Standard Emission: 0.0005 PERCENT DRIFT ANNUAL AVERAGEDid factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: OPERATING PERMIT Control Method: (P) HIGH EFFICIENCY MIST ELIMINATOREst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: MASS EMISSION RATES ARE NOT ESTABLISHED BY THE PSD PERMIT.


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: Emission Limit 2: Standard Emission: 0.0005 PERCENT DRIFT ANNUAL AVERAGEDid factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSD

Other Applicable Requirements: OPERATING PERMIT Control Method: (P) HIGH EFFICIENCY MIST ELIMINATOREst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: MASS EMISSION RATES ARE NOT ESTABLISHED BY THE PSD PERMIT.


PROCESS NAME: EMERGENCY DIESEL GENERATOR

Process Type: 17.110 (Fuel Oil (ASTM # 1,2, includes kerosene, aviation, diesel fuel))

Primary Fuel: DIESEL

Throughput: 1250.00 HP

Process Notes:


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: Emission Limit 2: Standard Emission: 0.1500 G/HP-HR ANNUAL AVERAGEDid factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: OPERATING PERMIT Control Method: (P) ULTRA LOW SULFUR DIESEL AND GOOD COMBUSTION PRACTICESEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1:

Emission Limit 2: Standard Emission: 0.1500 G/HP-HR ANNUAL AVERAGEDid factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: OPERATING PERMIT Control Method: (P) ULTRA LOW SULFUR DIESEL AND GOOD COMBUSTION PRACTICESEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: 630-08-0Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds ) Emission Limit 1: Emission Limit 2: Standard Emission: 2.6000 G/HP-HR ANNUAL AVERAGEDid factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: OPERATING PERMIT Control Method: (P) ULTRA LOW SULFUR DIESEL AND GOOD COMBUSTION PRACTICESEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: VOCTest Method: UnspecifiedPollutant Group(s): ( Volatile Organic Compounds (VOC) ) Emission Limit 1: Emission Limit 2: Standard Emission: 1.0000 G/HP-HR ANNUAL AVERAGEDid factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSD

Other Applicable Requirements: OPERATING PERMIT Control Method: (P) ULTRA LOW SULFUR DIESEL AND GOOD COMBUSTION PRACTICESEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:




CAS Number: 74-82-8Test Method: UnspecifiedPollutant Group(s): ( Greenhouse Gasses (GHG) , Organic Compounds (all) , Organic Non-HAP Compounds ) Emission Limit 1: Emission Limit 2: Standard Emission: 0.0061 LB/MM BTU Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: OPERATING PERMIT Control Method: (P) PROPER OPERATION AND GOOD COMBUSTION PRACTICESEst. % Efficiency:Compliance Verified: Unknown

Pollutant/Compliance Notes:




PROCESS NAME: EMERGENCY FIRE PUMP

Process Type: 17.210 (Fuel Oil (ASTM # 1,2, includes kerosene, aviation, diesel fuel))

Primary Fuel: DIESEL

Throughput: 350.00 HP

Process Notes:


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: Emission Limit 2: Standard Emission: 0.1500 G/HP-HR ANNUAL AVERAGEDid factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSD

Other Applicable Requirements: NSPS , OPERATING PERMIT Control Method: (P) ULTRA LOW SULFUR DIESEL AND GOOD COMBUSTION PRACTICESEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: Emission Limit 2: Standard Emission: 0.1500 G/HP-HR ANNUAL AVERAGEDid factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: NSPS , OPERATING PERMIT Control Method: (P) ULTRA LOW SULFUR DIESEL AND GOOD COMBUSTION PRACTICESEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: 630-08-0Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds ) Emission Limit 1: Emission Limit 2: Standard Emission: 2.6000 G/HP-HR ANNUAL AVERAGEDid factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: OPERATING PERMIT Control Method: (P) ULTRA LOW SULFUR DIESEL AND GOOD COMBUSTION PRACTICESEst. % Efficiency:Compliance Verified: Unknown



CAS Number: VOCTest Method: UnspecifiedPollutant Group(s): ( Volatile Organic Compounds (VOC) ) Emission Limit 1: Emission Limit 2: Standard Emission: 1.0000 G/HP-HR ANNUAL AVERAGEDid factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: OPERATING PERMIT Control Method: (P) ULTRA LOW SULFUR DIESEL AND GOOD COMBUSTION PRACTICESEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:




CAS Number: 74-82-8

Test Method: UnspecifiedPollutant Group(s): ( Greenhouse Gasses (GHG) , Organic Compounds (all) , Organic Non-HAP Compounds ) Emission Limit 1: Emission Limit 2: Standard Emission: 0.0061 LB/MM BTU Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: OPERATING PERMIT Control Method: (P) PROPER OPERATION AND GOOD COMBUSTION PRACTICESEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:




RBLC ID: LA-0248 (draft) DateDeterminationLast Updated: 12/08/2011


CONSOLIDATED ENVIRONMENTAL MANAGEMENT INC - NUCOR PermitNumber:

PSD-LA-751

Facility Name: DIRECT REDUCTION IRON PLANT Permit Date: 01/27/2011(actual)

Facility Contact: STEVE ROWLAN (704) 366-7000 FRS Number: 110037583442

Facility Description: The DRI process reduces the iron oxide content of iron ore pellets into iron metal through direct contact with areducing gas. The effectiveness of this reduction process is called metallization, and the process equipment willbe designed to achieve a metallization rate of at least 92% of the oxides within the ore. The reduction will takeplace in a countercurrent vertical shaft furnace, where reducing gas passes up through iron oxide pellets, whichfeed through the furnace by gravity. The major elements of the DRI process include the following: (1) iron oxidepreparation; (2) reducing gas preparation; (3) DRI reactor shaft furnace; (4) spent reducing gas preparation forreuse, (5) DRI product handling; and (6) ancillary operations, including a package boiler, two cooling towers,and a flare for emergency situations.

SIC Code: 3312

Permit Type: B: Add new process to existing facility NAICS Code: 331111


Facility County: ST JAMES PARISH

Facility State: LA




Kermit [email protected]

Permit Notes: This PSD permit also evaluated BACT for Green House Gases


PROCESSNAME:

DRI-101 DRI Unit #1 Iron Oxide Day Bins Dust Collection

Process Type: 81.900 (Other Ferrous Metal Industry Processes)

Primary Fuel: Throughput: 3858090.00 Tons/yr

Process Notes: The DRI process is fed iron oxide in pellet form to provide a consistent size of material in the shaft furnace to reduce the likelihood of fused product.Batches of pellets directed to the DRI facility will be screened prior to storage in the Iron Oxide Day Bins. The Iron Oxide Day Bins provide a continuousfeed of pellets to the shaft furnace. The continuous feed is again screened before being transferred by the furnace feed conveyor to the charge hopper atthe top of the furnace.

POLLUTANT NAME: Particulate matter, filterable < 10 µ (FPM10)

CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 1.1900 LB/H Emission Limit 2: 4.3200 T/YR Standard Emission: 0.0020 GRAINS/DSCF Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (A) Fabric filter baghouse achieving at least 99.5% control of PM10/PM2.5. Additionally, hooded conveyors and

enclosed transfer stations will be installed to limit emissions from material handlingEst. % Efficiency: 99.500Compliance Verified: YesPollutant/Compliance Notes:


PROCESSNAME:

DRI-201 DRI Unit #2 Iron Oxide Day Bins Dust Collection


Primary Fuel: Throughput: 3858090.00 tons/yr

Process Notes: The DRI process is fed iron oxide in pellet form to provide a consistent size of material in the shaft furnace to reduce the likelihood of fused product.Batches of pellets directed to the DRI facility will be screened prior to storage in the Iron Oxide Day Bins. The Iron Oxide Day Bins provide acontinuous feed of pellets to the shaft furnace. The continuous feed is again screened before being transferred by the furnace feed conveyor to the chargehopper at the top of the furnace.


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 1.1900 LB/H Emission Limit 2: 4.3200 T/YR Standard Emission: 0.0020 GRAINS/DSCF

Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (A) Fabric filter baghouse achieving at least 99.5% control of PM10/PM2.5. Additionally, hooded conveyors and



PROCESSNAME:

DRI-102 DRI Unit #1 Iron Oxide Screen Dust Collection









PROCESSNAME:

DRI-202 DRI Unit #2 Iron Oxide Screen Dust Collection








PROCESSNAME:

DRI-105 DRI Unit #1 Furnace Feed Conveyor Baghouse








PROCESSNAME:

DRI-205 DRI Unit #2 Furnace Feed Conveyor Baghouse


Primary Fuel: Throughput: 3858090.00

Process Notes: The DRI process is fed iron oxide in pellet form to provide a consistent size of material in the shaft furnace to reduce the likelihood of fused product.Batches of pellets directed to the DRI facility will be screened prior to storage in the Iron Oxide Day Bins. The Iron Oxide Day Bins provide acontinuous feed of pellets to the shaft furnace. The continuous feed is again screened before being transferred by the furnace feed conveyor to the chargehopper at the top of the furnace.





PROCESSNAME:

DRI-103 DRI Unit #1 Coating Bin Filter



Process Notes: Iron oxide pellets are given a light coating of pulverized limestone prior to being transferred to the furnace. The limestone coating helps to reduce thetendency of the pellets to fuse together during the reduction process. Water is added to the limestone to make a water-based slurry, which is then appliedto the pellets. The pulverized limestone is periodically received by truck and pneumatically conveyed into a storage bin. The act of filling the Iron OxideCoating Bin may generate dust emissions


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 0.1200 LB/H Emission Limit 2: 0.0200 T/YR Standard Emission: 0.0200 GRAINS/DSCF Did factors, other then air pollution technology considerations influence the BACT decisions: N

Case-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (A) BACT for emissions of PM10 and PM2.5 from Iron Oxide Coating Bin is selected to be local collection and

control through a fabric filter employing enhanced filter mediaEst. % Efficiency: 99.500Compliance Verified: YesPollutant/Compliance Notes:


PROCESSNAME:

DRI-203 DRI Unit #2 Coating Bin Filter



Process Notes: Iron oxide pellets are given a light coating of pulverized limestone prior to being transferred to the furnace. The limestone coating helps to reduce thetendency of the pellets to fuse together during the reduction process. Water is added to the limestone to make a water-based slurry, which is then appliedto the pellets. The pulverized limestone is periodically received by truck and pneumatically conveyed into a storage bin. The act of filling the Iron OxideCoating Bin may generate dust emissions


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 0.1200 LB/H Emission Limit 2: 0.0200 T/YR Standard Emission: 0.0200 GRAINS/DSCF Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (A) BACT for emissions of PM10 and PM2.5 from Iron Oxide Coating Bin is selected to be local collection and

control through a fabric filter employing enhanced filter mediaEst. % Efficiency: 99.500Compliance Verified: YesPollutant/Compliance Notes:


PROCESSNAME:

DRI-104 DRI Unit #1 Iron Oxide Fines Handling



Process Notes: The screening and handling of iron oxide pellets generates a quantity of undersized material referred to as fines. This material is too small to charge tothe shaft furnace, where it would clog the flow of reducing gas, and contribute to the problem of pellets fusing together during the reduction reaction,and impeding the flow of pellets out of the furnace. Iron oxide fines are stored at the DRI units temporarily. The fines will be stored in an outdoor pile.Fines will typically be transferred by truck and front end loader.


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 0.0700 LB/H Emission Limit 2: 0.0900 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (B) Nucor will control dust emissions through the application of a chemical surface stabilizer on the iron oxide

storage pile. Water sprays will be used locally to control dust generation from activities such asstacking/reclaiming and pile maintenance activity. These activities will be minimized as much as practicable inorder to prevent unnecessary dust emissions.

Est. % Efficiency: 95.000Compliance Verified: NoPollutant/Compliance Notes:


PROCESSNAME:

DRI-204 DRI Unit #1 Iron Oxide Fines Handling



Process Notes: The screening and handling of iron oxide pellets generates a quantity of undersized material referred to as fines. This material is too small to charge tothe shaft furnace, where it would clog the flow of reducing gas, and contribute to the problem of pellets fusing together during the reduction reaction,and impeding the flow of pellets out of the furnace. Iron oxide fines are stored at the DRI units temporarily. The fines will be stored in an outdoor pile.Fines will typically be transferred by truck and front end loader.


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 0.0700 LB/H Emission Limit 2: 0.0900 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (B) Nucor will control dust emissions through the application of a chemical surface stabilizer on the iron oxide

storage pile. Water sprays will be used locally to control dust generation from activities such asstacking/reclaiming and pile maintenance activity. These activities will be minimized as much as practicable inorder to prevent unnecessary dust emissions.

Est. % Efficiency: 95.000Compliance Verified: NoPollutant/Compliance Notes:


PROCESSNAME:

DRI-113 - DRI Unit #1 Process Water Cooling Tower


Primary Fuel: Throughput: 26857.00 gpm

Process Notes: The cross-flow cooling towers continuously circulate cooling water through heat exchangers and other equipment where the water absorbs heat. That

Process Notes: The cross-flow cooling towers continuously circulate cooling water through heat exchangers and other equipment where the water absorbs heat. Thatheat is then rejected to the atmosphere by the partial evaporation of the water in cooling towers where up-flowing air is contacted with the circulatingdown-flow of water. The loss of evaporated water into the air exhausted to the atmosphere is replaced by "make-up" water.


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 0.1100 LB/H Emission Limit 2: 0.4000 T/YR Standard Emission: 1000.0000 MG/L TDS Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (B) BACT is a combination of less than or equal to 1,000 milligrams per liter TDS concentration in the cooling

water and drift eliminators employing a drift maximum of 0.0005%. Est. % Efficiency:Compliance Verified: NoPollutant/Compliance Notes: The design drift efficiency of 0.0005% and cooling tower circulating water rate shall be verified by vendor

certification. Collect a grab sample of the cooling water at least once per day for seven consecutive operatingdays, analyze each sample in accordance with Standard Method 2540 C or EPA Method 160.1, and record theresults. Subsequently, collect a grab sample of the cooling water at least once per week, analyze each sampleusing one of the aforementioned methods, and record the results. Maintain the assembled cooling tower drifteliminators consistent with the manufacturer's recommendation as described in the operating manual for thecooling tower. Compliance shall be documented by maintaining a log of maintenance activity performed on thecooling tower drift eliminators.


PROCESSNAME:

DRI-213 - DRI Unit #2 Process Water Cooling Tower





CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 0.1100 LB/H Emission Limit 2: 0.4000 T/YR Standard Emission: 1000.0000 MG/L TDS Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (B) BACT is a combination of less than or equal to 1,000 milligrams per liter TDS concentration in the cooling

water and drift eliminators employing a drift maximum of 0.0005%. Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: The design drift efficiency of 0.0005% and cooling tower circulating water rate shall be verified by vendor



PROCESSNAME:

DRI-114 - DRI Unit #1 Clean Water Cooling Tower





CAS Number: PM

Test Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 0.0700 LB/H Emission Limit 2: 0.2900 T/YR Standard Emission: 1000.0000 MG/L TDS Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (B) BACT is a combination of less than or equal to 1,000 milligrams per liter TDS concentration in the cooling




PROCESSNAME:

DRI-214 - DRI Unit #1 Clean Water Cooling Tower





CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 0.0700 LB/H

Emission Limit 1: 0.0700 LB/H Emission Limit 2: 0.2900 T/YR Standard Emission: 1000.0000 MG/L TDS Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (B) BACT is a combination of less than or equal to 1,000 milligrams per liter TDS concentration in the cooling




PROCESSNAME:

DRI-117 - Briquetting Mill

Process Type: 81.290 (Other Steel Manufacturing Processes)


Process Notes: The screening and handling of DRI pellets results in undersize material, or fines. DRI fines will be recycled and formed into bricks for use in the blastfurnace or off-site EAF furnaces. Fines will be mixed with a cement binder, and then pressed in molds to form bricks of uniform size and shape. Aftercuring on racks, the bricks are transported for shipment off-site.


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 0.2900 LB/H Emission Limit 2: 0.2600 T/YR Standard Emission: 0.0022 GRAINS/DSCF

Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (A) High-energy wet scrubber. Additionally, hooded conveyors and enclosed transfer stations will be installed to

limit emissions from material handling.Est. % Efficiency: 99.000Compliance Verified: NoPollutant/Compliance Notes: Baghouses often are capable of 99.5% removal efficiencies, and baghouse removal efficiency is relatively level

across the particle size range. However, DRI particles are known to react with oxygen in the atmosphere,reoxidizing in an exothermic reaction. This reoxidation process frequently causes fires when the DRI material isimproperly handled, particularly when freshly discharged from the furnace before being passivated. The natureof the DRI particulate being captured makes the application of a fabric filter to this source a significant safetyhazard, and thus a baghouse is technically infeasible.


PROCESSNAME:

DRI-118 - DRI Barge Loading Dock

Process Type: 99.190 (Other Fugitive Dust Sources)


Process Notes: DRI pellets will be loaded for shipment to other Nucor facilities by barge. Due to the special handling requirement of the DRI product, the loadingdock will be specialized for the loading of DRI product.


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 0.7800 LB/H Emission Limit 2: 0.6500 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (A) High-energy wet scrubber. Additionally, hooded conveyors and enclosed transfer stations will be installed to

limit emissions from material handling.

Est. % Efficiency: 99.000Compliance Verified: NoPollutant/Compliance Notes: A scrubber will be installed on the product storage silos for DRI dust control. Wet suppression of dust generating

sources by water sprays will be utilized at each storage pile site. Baghouses often are capable of 99.5% removalefficiencies, and baghouse removal efficiency is relatively level across the particle size range. However, DRIparticles are known to react with oxygen in the atmosphere, reoxidizing in an exothermic reaction. Thisreoxidation process frequently causes fires when the DRI material is improperly handled, particularly whenfreshly discharged from the furnace before being passivated. The nature of the DRI particulate being capturedmakes the application of a fabric filter to this source a significant safety hazard, and thus a baghouse istechnically infeasible.


PROCESSNAME:

DRI-115 - Product Screen Dust Collection



Process Notes: The DRI fines collected from the screening operation are transported to the Briquetting Mill. This transportation operation generates particulatematter emissions.


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 1.4000 LB/H Emission Limit 2: 0.9600 T/YR Standard Emission: 0.0020 GRAINS/DSCF Did factors, other then air pollution technology considerations influence the BACT decisions: YCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (A) High-energy wet scrubber Est. % Efficiency: 99.000Compliance Verified: NoPollutant/Compliance Notes: Baghouses often are capable of 99.5% removal efficiencies, and baghouse removal efficiency is relatively level

Pollutant/Compliance Notes: Baghouses often are capable of 99.5% removal efficiencies, and baghouse removal efficiency is relatively levelacross the particle size range. However, DRI particles are known to react with oxygen in the atmosphere,reoxidizing in an exothermic reaction. This reoxidation process frequently causes fires when the DRI material isimproperly handled, particularly when freshly discharged from the furnace before being passivated. The natureof the DRI particulate being captured makes the application of a fabric filter to this source a significant safetyhazard, and thus a baghouse is technically infeasible.


PROCESS NAME: DRI-116 - Screened Product Transfer Dust Collection



Process Notes: Prior to final shipment, the DRI pellets are screened to remove fines. This screening process generates particulate matter emissions.


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 0.7100 LB/H Emission Limit 2: 0.4900 T/YR Standard Emission: 0.0020 GRAINS/DSCF Did factors, other then air pollution technology considerations influence the BACT decisions: YCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (A) high-energy wet scrubberEst. % Efficiency: 99.000Compliance Verified: NoPollutant/Compliance Notes: Baghouses often are capable of 99.5% removal efficiencies, and baghouse removal efficiency is relatively level



PROCESSNAME:

DRI-107 - DRI Unit No. 1 Furnace Dust Collection



Process Notes: The DRI Product exits the cooling zone of the shaft furnace and falls onto a waiting conveyor for transport to the product silos. This discharge point hasa high potential for dust generation, since any fines generated during the action of the pellets passing through the reactor are also discharged.


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 0.9300 LB/H Emission Limit 2: 2.9200 T/YR Standard Emission: 0.0020 GRAINS/DSCF Did factors, other then air pollution technology considerations influence the BACT decisions: YCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (A) high-energy wet scrubberEst. % Efficiency: 99.000Compliance Verified: NoPollutant/Compliance Notes: Baghouses often are capable of 99.5% removal efficiencies, and baghouse removal efficiency is relatively level


POLLUTANT NAME: Nitrogen Oxides (NOx)

CAS Number: 10102Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) ) Emission Limit 1: 1.2400 LB/H Emission Limit 2: 4.7400 T/YR

Standard Emission: 0.0700 LB/MMBTU Did factors, other then air pollution technology considerations influence the BACT decisions: YCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) The seal gas is removed before the flue gas is treated for NOX control. Est. % Efficiency:Compliance Verified: NoPollutant/Compliance Notes: The SCR controlling NOX from the reformer contributes ammonia to the reformer flue gas. Ammonia would

react with the lime coating on the iron oxide pellets to form ammonium bicarbonate and ammonium carbamate,which are a sticky white salt. These compounds would tend to promote fusion of the iron ore pellets, which cancause a significant process upset as the clumped product cannot be removed from the shaft furnace. Nitrogenoxides (NOx)


CAS Number: 630-08-0Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds ) Emission Limit 1: 0.7100 LB/H Emission Limit 2: 2.7100 T/YR Standard Emission: 0.0400 LB/MMBTU Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) BACT for CO is determined as good combustion practices for the Reformer Flue gas and so no additional

control is feasible for the use of a small portion of this flue gas as seal gas.Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: Carbon monoxide (CO)


PROCESS NAME: DRI-207 - DRI Unit No. 2 Furnace Dust Collection



Throughput: 2755778.00 tons/yr

Process Notes: Prior to final shipment, the DRI pellets are screened to remove fines. This screening process generates particulate matter emissions.


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 0.9300 LB/H Emission Limit 2: 2.9200 T/YR Standard Emission: 0.0020 GRAINS/DSCF Did factors, other then air pollution technology considerations influence the BACT decisions: YCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (A) High-energy wet scrubberEst. % Efficiency: 99.000Compliance Verified: NoPollutant/Compliance Notes: Baghouses often are capable of 99.5% removal efficiencies, and baghouse removal efficiency is relatively level



CAS Number: 10102Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) ) Emission Limit 1: 1.2400 LB/H Emission Limit 2: 4.7400 T/YR Standard Emission: 0.0700 LB/MMBTU Did factors, other then air pollution technology considerations influence the BACT decisions: YCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) The seal gas is removed before the flue gas is treated for NOX control. Est. % Efficiency:Compliance Verified: Unknown

Pollutant/Compliance Notes: The SCR controlling NOX from the reformer contributes ammonia to the reformer flue gas. Ammonia wouldreact with the lime coating on the iron oxide pellets to form ammonium bicarbonate and ammonium carbamate,which are a sticky white salt. These compounds would tend to promote fusion of the iron ore pellets, which cancause a significant process upset as the clumped product cannot be removed from the shaft furnace. Nitrogenoxides (NOx)


CAS Number: 630-08-0Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds ) Emission Limit 1: 0.7100 LB/H Emission Limit 2: 2.7100 T/YR Standard Emission: 0.0400 LB/MMBTU Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) BACT for CO isdetermined as good combustion practices for the Reformer Flue gas and so no additional

control is feasible for the use of a small portion of this flue gas as seal gas.Est. % Efficiency:Compliance Verified: NoPollutant/Compliance Notes: Carbon monoxide (CO)


PROCESSNAME:

DRI-109 - DRI Unit #1 Package Boiler Flue Stack


Primary Fuel: Natural Gas

Throughput: 1760.00 Billion Btu/yr

Process Notes: The package boilers provide steam to each DRI unit. The steam is primarily used to heat the reboiler in the acid gas absorption system, as well as forutility purposes.


CAS Number: PMTest Method: EPA/OAR Mthd 201A

Pollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 2.3800 LB/H Emission Limit 2: 8.6400 T/YR Standard Emission: 0.0046 GRAINS/DSCF Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (P) good combustion practicesEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: 630-08-0Test Method: EPA/OAR Mthd 10Pollutant Group(s): ( InOrganic Compounds ) Emission Limit 1: 11.4200 LB/H Emission Limit 2: 41.5400 T/YR Standard Emission: 0.0390 LB/MMBTU Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (P) Good Combustion PracticesEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:

POLLUTANT NAME: Sulfur Dioxide (SO2)

CAS Number: 7446-09-5Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Sulfur (SOx) ) Emission Limit 1: 0.0900 LB/H Emission Limit 2: 0.3300 T/YR Standard Emission:

Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (P) Emissions of SO2 are usually attributable to the sulfur contained within the fuel being combusted. Therefore

the use of a low sulfur fuel can drastically reduce emissions of SO2 when compared to other potential fuels.Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: Sulfur dioxide: Purchase natural gas with a sulfur content less than 2000 grains per million standard cubic feet of

gas. Sulfur content shall be monitored and recorded monthly and shall be based on either the natural gas analysisprovided by the supplier or direct sampling by the facility


CAS Number: 10102Test Method: EPA/OAR Mthd 7EPollutant Group(s): ( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) ) Emission Limit 1: 0.9400 LB/H Emission Limit 2: 3.4100 T/YR Standard Emission: 0.0032 LB/MMBTU Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements: NSPS Control Method: (B) BACT for the package boiler is selected to be low NOX burners, combined with selective catalytic reduction.Est. % Efficiency: 90.000Compliance Verified: NoPollutant/Compliance Notes:


CAS Number: VOCTest Method: UnspecifiedPollutant Group(s): ( Volatile Organic Compounds (VOC) ) Emission Limit 1: 1.5600 LB/H Emission Limit 2: 4.7500 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSD

Other Applicable Requirements:Control Method: (P) good combustion practicesEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


PROCESSNAME:

DRI-209 - DRI Unit #2 Package Boiler Flue Stack


Primary Fuel: Natural Gas


Process Notes: The package boilers provide steam to each DRI unit. The steam is primarily used to heat the reboiler in the acid gas absorption system, as well as forutility purposes.


CAS Number: PMTest Method: EPA/OAR Mthd 201APollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 2.3800 LB/H Emission Limit 2: 8.6400 T/YR Standard Emission: 0.0046 GRAINS/DSCF Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (P) good combustion practicesEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: 630-08-0Test Method: EPA/OAR Mthd 10

Pollutant Group(s): ( InOrganic Compounds ) Emission Limit 1: 11.4200 LB/H Emission Limit 2: 41.5400 T/YR Standard Emission: 0.0390 LB/MMBTU Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (P) Good Combustion PracticesEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: 7446-09-5Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Sulfur (SOx) ) Emission Limit 1: 0.0900 LB/H Emission Limit 2: 0.3300 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (P) Emissions of SO2 are usually attributable to the sulfur contained within the fuel being combusted. Therefore

the use of a low sulfur fuel can drastically reduce emissions of SO2 when compared to other potential fuels.Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: Sulfur dioxide: Purchase natural gas with a sulfur content less than 2000 grains per million standard cubic feet of

gas. Sulfur content shall be monitored and recorded monthly and shall be based on either the natural gas analysisprovided by the supplier or direct sampling by the facility


CAS Number: 10102Test Method: EPA/OAR Mthd 7EPollutant Group(s): ( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) ) Emission Limit 1: 0.9400 LB/H

Emission Limit 2: 3.4100 T/YR Standard Emission: 0.0032 LB/MMBTU Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements: NSPS Control Method: (B) BACT for the package boiler is selected to be low NOX burners, combined with selective catalytic reduction.Est. % Efficiency: 90.000Compliance Verified: NoPollutant/Compliance Notes:


CAS Number: VOCTest Method: UnspecifiedPollutant Group(s): ( Volatile Organic Compounds (VOC) ) Emission Limit 1: 1.1900 LB/H Emission Limit 2: 4.7500 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (P) good combustion practicesEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


PROCESSNAME:

DRI-112 - DRI Unit No. 1 Product storage silo Dust Collection



Process Notes: the DRI Product exits the cooling zone of the shaft furnace and falls onto a waiting conveyor for transport to the product silos. Transfer into and out ofthe Silo has a high potential for dust generation, since any fines generated during the action of the pellets passing through the reactor are also discharged.


CAS Number: PMTest Method: EPA/OAR Other Test Mthd 27Pollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 0.9900 LB/H Emission Limit 2: 3.3700 T/YR Standard Emission: 0.0100 LB/MMBTU Did factors, other then air pollution technology considerations influence the BACT decisions: YCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (A) In order to prevent the reducing gas from escaping the furnace, a higher pressure gas called seal gas is

applied at both the charging and discharging opening. The seal gas is allowed to escape the furnace while thereducing gas is retained. This seal gas is merely a small amount of cooled flue gas from the reformer combustionside, and primarily consists of atmospheric nitrogen, carbon dioxide and water vapor.

Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: Sulfur dioxide and particulate matter BACT was determined to treat the spent reducing gas being sent to the

Reformer as combustion fuel and so no additional control is feasible for the seal gas. Emissions of these twopollutants are expected to be less than five tons per year combined. It should be noted that all of the spentreducing gas has particulate matter emission controlled. Particulate matter (10 microns or less) (PM10)


CAS Number: 630-08-0Test Method: EPA/OAR Mthd 10Pollutant Group(s): ( InOrganic Compounds ) Emission Limit 1: 0.5700 LB/H Emission Limit 2: 2.1700 T/YR Standard Emission: 0.0040 LB/MMBTU Did factors, other then air pollution technology considerations influence the BACT decisions: YCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (P) In order to prevent the reducing gas from escaping the furnace, a higher pressure gas called seal gas is applied

at both the charging and discharging opening. The seal gas is allowed to escape the furnace while the reducing gasis retained. This seal gas is merely a small amount of cooled flue gas from the reformer combustion side, andprimarily consists of atmospheric nitrogen, carbon dioxide and water vapor. BACT was good combustionpractices in the reformer.

Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: 10102Test Method: EPA/OAR Mthd 7EPollutant Group(s): ( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) ) Emission Limit 1: 0.9900 LB/H Emission Limit 2: 3.7900 T/YR Standard Emission: 0.0700 LB/MMBTU Did factors, other then air pollution technology considerations influence the BACT decisions: YCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (P) The seal gas is removed before the flue gas is treated for NOX control. The SCR controlling NOX from the

reformer contributes ammonia to the reformer flue gas. Ammonia would react with the lime coating on the ironoxide pellets to form ammonium bicarbonate and ammonium carbamate, which are a sticky white salt. Thesecompounds would tend to promote fusion of the iron ore pellets, which can cause a significant process upset asthe clumped product cannot be removed from the shaft furnace

Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: Nitrogen oxides (NOx)


PROCESSNAME:

DRI-212 - DRI Unit No. 2 Product storage silo Dust Collection



Process Notes: the DRI Product exits the cooling zone of the shaft furnace and falls onto a waiting conveyor for transport to the product silos. Transfer into and out ofthe Silo has a high potential for dust generation, since any fines generated during the action of the pellets passing through the reactor are also discharged.


CAS Number: PM

Test Method: EPA/OAR Other Test Mthd 27Pollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 0.9900 LB/H Emission Limit 2: 3.3700 T/YR Standard Emission: 0.0100 LB/MMBTU Did factors, other then air pollution technology considerations influence the BACT decisions: YCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (A) In order to prevent the reducing gas from escaping the furnace, a higher pressure gas called seal gas is

applied at both the charging and discharging opening. The seal gas is allowed to escape the furnace while thereducing gas is retained. This seal gas is merely a small amount of cooled flue gas from the reformer combustionside, and primarily consists of atmospheric nitrogen, carbon dioxide and water vapor.

Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: Sulfur dioxide and particulate matter BACT was determined to treat the spent reducing gas being sent to the

Reformer as combustion fuel and so no additional control is feasible for the seal gas. Emissions of these twopollutants are expected to be less than five tons per year combined. It should be noted that all of the spentreducing gas has particulate matter emission controlled. Particulate matter (10 microns or less) (PM10)


CAS Number: 630-08-0Test Method: EPA/OAR Mthd 10Pollutant Group(s): ( InOrganic Compounds ) Emission Limit 1: 0.5700 LB/H Emission Limit 2: 2.1700 T/YR Standard Emission: 0.0040 LB/MMBTU Did factors, other then air pollution technology considerations influence the BACT decisions: YCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (P) In order to prevent the reducing gas from escaping the furnace, a higher pressure gas called seal gas is applied

at both the charging and discharging opening. The seal gas is allowed to escape the furnace while the reducing gasis retained. This seal gas is merely a small amount of cooled flue gas from the reformer combustion side, andprimarily consists of atmospheric nitrogen, carbon dioxide and water vapor. BACT was good combustionpractices in the reformer.



CAS Number: 10102Test Method: EPA/OAR Mthd 7EPollutant Group(s): ( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) ) Emission Limit 1: 0.9900 LB/H Emission Limit 2: 3.7900 T/YR Standard Emission: 0.0700 LB/MMBTU Did factors, other then air pollution technology considerations influence the BACT decisions: YCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (P) The seal gas is removed before the flue gas is treated for NOX control. The SCR controlling NOX from the

reformer contributes ammonia to the reformer flue gas. Ammonia would react with the lime coating on the ironoxide pellets to form ammonium bicarbonate and ammonium carbamate, which are a sticky white salt. Thesecompounds would tend to promote fusion of the iron ore pellets, which can cause a significant process upset asthe clumped product cannot be removed from the shaft furnace

Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: Nitrogen oxides (NOx)


PROCESSNAME:

DRI-110 - DRI Unit No. 1 Hot Flare

Process Type: 19.390 (Other Flares)

Primary Fuel: DRI Reducing Gas

Throughput: 1180.00 acfm

ProcessNotes:

The reducing furnace must run as close to steady state operation as possible in order to produce product of acceptable quality. Due to the nature of thereducing gas recycle system periodic shifts in pressure may occur. The pressure of the reducing gas must be maintained below that of the seal gas systemor an uncontrolled release of reducing gas will result from the top seal and the bottom seal. To maintain this condition, the reducing gas is occasionallyflared to prevent a rise in pressure. The Hot Flare prevents an uncontrolled release of carbon monoxide from the system by combusting the reducing gas.

POLLUTANT NAME: Particulate matter, filterable (FPM)

CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) )

Pollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 0.1300 LB/H Emission Limit 2: 0.2700 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (P) the best available technology for controlling PM10/PM2.5 from the natural gas pilot is good combustion

practiceEst. % Efficiency: 50.000Compliance Verified: NoPollutant/Compliance Notes: The reducing gas contains incombustible particulate matter in the gas stream as gas is recycled from the shaft

furnace. Therefore, the control of particulate from the hot flare is best addressed by cleaning of the reducing gasprior to its combustion. Particulate matter cleaning of the spent reducing gas has already been addressed, soBACT for PM is venting to the Hot Flare after the spent reducing gas has been cleaned by the wet scrubbersdescribed as BACT for the Reformer Flue Gas. The flare shall be of the continuous pilot variety, fueled bynatural gas.


CAS Number: 10102Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) ) Emission Limit 1: 1.2700 LB/H Emission Limit 2: 2.5800 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (P) A low-NOX fuel is one which results in a lower generation rate of NOX over traditional fossil fuels, on an

equal energy basis. DRI reducing gas is a low-NOX fuel, generating less NOX per unit of energy as natural gas.This property is due to the low-BTU value of reducing gas, which burns at a cooler temperature, preventing theformation of much of the NOX seen with hotter natural gas combustion.



CAS Number: 630-08-0Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds ) Emission Limit 1: 1.4700 LB/H Emission Limit 2: 2.5800 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (P) The reducing gas is rich in carbon monoxide and hydrogen. The pilot for the flare is natural gas. Good

combustion practices are used to reduce emissions of CO, as well as other pollutants, by optimizing conditions inthe combustion zone of a fuel burning source. Good combustion practices typically entail introducing the properratio of combustion air to the fuel, maintaining a minimum temperature in the firebox of the combustor, or aminimum residence time of fuel and air in the combustion zone. By employing good combustion practices COemissions may be greatly reduced.

Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: The hot flare will combust reducing gas, which contains a significant portion of carbon monoxide. Nucor will

install a flare tip employing good combustion practices to control the generation of CO emissions due toincomplete combustion of reducing gas.


PROCESSNAME:

DRI-210 - DRI Unit No. 1 Hot Flare

Process Type: 19.390 (Other Flares)

Primary Fuel: DRI Reducing Gas


ProcessNotes:

The reducing furnace must run as close to steady state operation as possible in order to produce product of acceptable quality. Due to the nature of thereducing gas recycle system periodic shifts in pressure may occur. The pressure of the reducing gas must be maintained below that of the seal gas systemor an uncontrolled release of reducing gas will result from the top seal and the bottom seal. To maintain this condition, the reducing gas is occasionallyflared to prevent a rise in pressure. The Hot Flare prevents an uncontrolled release of carbon monoxide from the system by combusting the reducing gas.


CAS Number: PMTest Method: Unspecified

Test Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 0.1300 LB/H Emission Limit 2: 0.2700 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (P) the best available technology for controlling PM10/PM2.5 from the natural gas pilot is good combustion

practices.Est. % Efficiency: 50.000Compliance Verified: NoPollutant/Compliance Notes: The reducing gas contains incombustible particulate matter in the gas stream as gas is recycled from the shaft

furnace. Therefore, the control of particulate from the hot flare is best addressed by cleaning of the reducing gasprior to its combustion. Particulate matter cleaning of the spent reducing gas has already been addressed, soBACT for PM is venting to the Hot Flare after the spent reducing gas has been cleaned by the wet scrubbersdescribed as BACT for the Reformer Flue Gas. The flare shall be of the continuous pilot variety, fueled bynatural gas.


CAS Number: 10102Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) ) Emission Limit 1: 1.2700 LB/H Emission Limit 2: 2.5800 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (P) A low-NOX fuel is one which results in a lower generation rate of NOX over traditional fossil fuels, on an

equal energy basis. DRI reducing gas is a low-NOX fuel, generating less NOX per unit of energy as natural gas.This property is due to the low-BTU value of reducing gas, which burns at a cooler temperature, preventing theformation of much of the NOX seen with hotter natural gas combustion.



CAS Number: 630-08-0Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds ) Emission Limit 1: 1.2700 LB/H Emission Limit 2: 2.5800 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (P) The reducing gas is rich in carbon monoxide and hydrogen. The pilot for the flare is natural gas. Good

combustion practices are used to reduce emissions of CO, as well as other pollutants, by optimizing conditions inthe combustion zone of a fuel burning source. Good combustion practices typically entail introducing the properratio of combustion air to the fuel, maintaining a minimum temperature in the firebox of the combustor, or aminimum residence time of fuel and air in the combustion zone. By employing good combustion practices COemissions may be greatly reduced.

Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: The hot flare will combust reducing gas, which contains a significant portion of carbon monoxide. Nucor will

install a flare tip employing good combustion practices to control the generation of CO emissions due toincomplete combustion of reducing gas.


PROCESSNAME:

DRI-111 - DRI Unit #1 Acid Gas Absorption Vent


Primary Fuel: Throughput: 30624.00 scfm

Process Notes: Acid gases, primarily hydrogen sulfide and carbon dioxide, are removed from the DRI top gas prior to its use as a fuel in the acid gas absorption unit.This unit is an amine-based absorption scrubber, which selectively dissolves acid gases from the top gas fuel. The amine solution is then regenerated byapplying heat in a steam reboiler, which liberates the acid gases from solution. The resulting gas stream is treated for the removal of sulfur compoundsprior to being vented.


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 0.0800 LB/H Emission Limit 2: 0.3100 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) Emissions of PM10 from the acid gas absorption vent are due to the absorption of PM10/PM2.5 in the

amine unit treating the top gas fuel, which is partially released during the amine regeneration step. Due to the lowquantity of emissions from the acid gas absorption vent, less than one ton per year from both DRI unitscombined, No technologies exist which meet the environmental, energy and economic considerations inherent ina BACT review. BACT for emissions of PM10/PM2.5 from the acid gas absorption vent is determined to be nocontrol.



CAS Number: 7446-09-5Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Sulfur (SOx) ) Emission Limit 1: 0.5800 LB/H Emission Limit 2: 2.1200 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (A) BACT is selected to be treatment of the acid gas stream through the use of a sulfur redox catalyst, such as

the SulfaTreat catalyst bed or LO-CAT Redox process, for the removal of H2S. Nucor will install a redox catalyston each of the acid gas absorption vents at the DRI facility for the control of sulfur compound emissions.

Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: The acid gas absorber selectively removes acid gases such as hydrogen sulfide and carbon dioxide from the top

Pollutant/Compliance Notes: The acid gas absorber selectively removes acid gases such as hydrogen sulfide and carbon dioxide from the topgas fuel, prior to combustion at the reformer. The amine-based absorption medium is then regenerated by theapplication of heat, releasing the absorbed acid gases as a separate gas stream. The efficiency of the DRI processbenefits from the removal of these gases, which are no longer heated during combustion. The energy saved fromno longer heating inert gases in the top gas fuel is then available for the reforming reaction. An added benefit isthe isolation of hydrogen sulfide, which can then be treated more effectively.


CAS Number: 630-08-0Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds ) Emission Limit 1: 0.7300 LB/H Emission Limit 2: 2.6500 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) Emissions of carbon monoxide from the acid gas absorption vent are due to the slight absorption of CO in

the amine unit treating the top gas fuel. Due to the low quantity of emissions from the acid gas absorption vent,no technologies exist which meet the environmental, energy and economic considerations inherent in a BACTreview. BACT for emissions of carbon monoxide from the acid gas absorption vent is determined to be no control



PROCESSNAME:

DRI-211 - DRI Unit #1 Acid Gas Absorption Vent


Primary Fuel: Throughput: 30624.00 scfm

Process Notes: Acid gases, primarily hydrogen sulfide and carbon dioxide, are removed from the DRI top gas prior to its use as a fuel in the acid gas absorption unit.This unit is an amine-based absorption scrubber, which selectively dissolves acid gases from the top gas fuel. The amine solution is then regenerated byapplying heat in a steam reboiler, which liberates the acid gases from solution. The resulting gas stream is treated for the removal of sulfur compoundsprior to being vented.


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 0.0800 LB/H Emission Limit 2: 0.3100 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: Emissions of PM10 from the acid gas absorption vent are due to the absorption of PM10/PM2.5 in the amine

unit treating the top gas fuel, which is partially released during the amine regeneration step. Due to the lowquantity of emissions from the acid gas absorption vent, less than one ton per year from both DRI unitscombined, No technologies exist which meet the environmental, energy and economic considerations inherent ina BACT review. BACT for emissions of PM10/PM2.5 from the acid gas absorption vent is determined to be nocontrol.


CAS Number: 7446-09-5Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Sulfur (SOx) ) Emission Limit 1: 0.5800 LB/H Emission Limit 2: 2.1200 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: The acid gas absorber selectively removes acid gases such as hydrogen sulfide and carbon dioxide from the top

Pollutant/Compliance Notes: The acid gas absorber selectively removes acid gases such as hydrogen sulfide and carbon dioxide from the topgas fuel, prior to combustion at the reformer. The amine-based absorption medium is then regenerated by theapplication of heat, releasing the absorbed acid gases as a separate gas stream. The efficiency of the DRI processbenefits from the removal of these gases, which are no longer heated during combustion. The energy saved fromno longer heating inert gases in the top gas fuel is then available for the reforming reaction. An added benefit isthe isolation of hydrogen sulfide, which can then be treated more effectively. BACT is selected to be treatmentof the acid gas stream through the use of a sulfur redox catalyst, such as the SulfaTreat catalyst bed or LO-CATRedox process, for the removal of H2S. Nucor will install a redox catalyst on each of the acid gas absorptionvents at the DRI facility for the control of sulfur compound emissions.


CAS Number: 630-08-0Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds ) Emission Limit 1: 0.7300 LB/H Emission Limit 2: 2.6500 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: Emissions of carbon monoxide from the acid gas absorption vent are due to the slight absorption of CO in the

amine unit treating the top gas fuel. Due to the low quantity of emissions from the acid gas absorption vent, notechnologies exist which meet the environmental, energy and economic considerations inherent in a BACTreview. BACT for emissions of carbon monoxide from the acid gas absorption vent is determined to be no control


PROCESSNAME:

DRI-106 - DRI Unit No. 1 Upper Seal Gas Vent

ProcessType:

81.290 (Other Steel Manufacturing Processes)

PrimaryFuel:



ProcessNotes:

Iron oxide pellets are fed continuously into the shaft furnace from the top, and pass down through the reaction area by gravity. Reducing gas from theReformer is passed through the iron oxide as it progresses through the furnace, in a countercurrent fashion. The DRI product then continuously exits thebottom of the furnace onto a waiting conveyor. In order to prevent the reducing gas from escaping the furnace, a higher pressure gas called seal gas isapplied at both the charging and discharging opening. The seal gas is allowed to escape the furnace while the reducing gas is retained. Due to the higherseal gas pressure, a portion is also entrained into the reactor and combined with the spent reducing gas travels back to the Reformer. This seal gas ismerely a small amount of cooled flue gas from the reformer combustion side, and primarily consists of atmospheric nitrogen, carbon dioxide and watervapor.


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 0.0700 LB/H Emission Limit 2: 0.2600 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: particulate matter BACT was determined to treat the spent reducing gas being sent to the Reformer as

combustion fuel and so no additional control is feasible for the seal gas. It is already treated before the seal gas issplit off.


CAS Number: 7446-09-5Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Sulfur (SOx) ) Emission Limit 1: 0.0200 LB/H Emission Limit 2: 0.0800 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:

Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: Sulfur dioxide BACT was determined to treat the spent reducing gas being sent to the Reformer as combustion

fuel. The seal gas is removed before the spent reducing gas is treated for SO2 control, and so no additionalcontrol is feasible for the seal gas.


CAS Number: 630-08-0Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds ) Emission Limit 1: 0.5300 LB/H Emission Limit 2: 2.0300 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: BACT for CO was already determined as good combustion practices for the Reformer Flue gas and so no

additional control is feasible for the use of a small portion of this flue gas as seal gas.


CAS Number: 10102Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) ) Emission Limit 1: 0.7500 LB/H Emission Limit 2: 2.8400 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: YCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) Est. % Efficiency:

Compliance Verified: UnknownPollutant/Compliance Notes: The seal gas is removed before the flue gas is treated for NOX control. The SCR controlling NOX from the

reformer contributes ammonia to the reformer flue gas. Ammonia would react with the lime coating on the ironoxide pellets to form ammonium bicarbonate and ammonium carbamate, which are a sticky white salt. Thesecompounds would tend to promote fusion of the iron ore pellets, which can cause a significant process upset asthe clumped product cannot be removed from the shaft furnace.


PROCESSNAME:

DRI-206 - DRI Unit No. 2 Upper Seal Gas Vent

ProcessType:

81.290 (Other Steel Manufacturing Processes)

PrimaryFuel:


ProcessNotes:

Iron oxide pellets are fed continuously into the shaft furnace from the top, and pass down through the reaction area by gravity. Reducing gas from theReformer is passed through the iron oxide as it progresses through the furnace, in a countercurrent fashion. The DRI product then continuously exits thebottom of the furnace onto a waiting conveyor. In order to prevent the reducing gas from escaping the furnace, a higher pressure gas called seal gas isapplied at both the charging and discharging opening. The seal gas is allowed to escape the furnace while the reducing gas is retained. Due to the higherseal gas pressure, a portion is also entrained into the reactor and combined with the spent reducing gas travels back to the Reformer. This seal gas ismerely a small amount of cooled flue gas from the reformer combustion side, and primarily consists of atmospheric nitrogen, carbon dioxide and watervapor.


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 0.0700 LB/H Emission Limit 2: 0.2600 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: Unknown

Pollutant/Compliance Notes: particulate matter BACT was determined to treat the spent reducing gas being sent to the Reformer ascombustion fuel and so no additional control is feasible for the seal gas. It is already treated before the seal gas issplit off.


CAS Number: 7446-09-5Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Sulfur (SOx) ) Emission Limit 1: 0.0200 LB/H Emission Limit 2: 0.0800 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: Sulfur dioxide BACT was determined to treat the spent reducing gas being sent to the Reformer as combustion

fuel. The seal gas is removed before the spent reducing gas is treated for SO2 control, and so no additionalcontrol is feasible for the seal gas.


CAS Number: 10102Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) ) Emission Limit 1: 0.7500 LB/H Emission Limit 2: 2.8400 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: The seal gas is removed before the flue gas is treated for NOX control. The SCR controlling NOX from the

Pollutant/Compliance Notes: The seal gas is removed before the flue gas is treated for NOX control. The SCR controlling NOX from thereformer contributes ammonia to the reformer flue gas. Ammonia would react with the lime coating on the ironoxide pellets to form ammonium bicarbonate and ammonium carbamate, which are a sticky white salt. Thesecompounds would tend to promote fusion of the iron ore pellets, which can cause a significant process upset asthe clumped product cannot be removed from the shaft furnace.


CAS Number: 630-08-0Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds ) Emission Limit 1: 0.5300 LB/H Emission Limit 2: 2.0300 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: BACT for CO was already determined as good combustion practices for the Reformer Flue gas and so no

additional control is feasible for the use of a small portion of this flue gas as seal gas.


PROCESSNAME:

DRI-108 - DRI Unit #1 Reformer Main Flue Stack

ProcessType:

81.200 (Steel Production (excludes Steel & Iron Foundry Processes))

PrimaryFuel:

Iron Ore and Natural Gas


ProcessNotes:

The Direct Reduction Iron process consists of two main components, a Reformer and the DRI reactor. Natural gas passes through special catalyst tubeswhere the natural gas dissociates into a reducing gas rich in carbon monoxide and hydrogen, which are the primary chemicals used to remove the oxygenfrom the iron ore. The reducing gas is fed in from the bottom of the DRI Reactor. The gas flows countercurrent to the descending iron ore pellets. At thetop of the reactor, the partially spent reducing gas exits and is recompressed, enriched with natural gas, preheated, and transported back to the gasreformer. The reformer reforms the mixture back to 95% hydrogen plus carbon monoxide, which is then ready for re-use by the direct reduction furnace.

Some of the reducing gas that has already passed over the iron ore in the DRI reactor (the spent reducing gas is also known as top gas) is mixed with thenatural gas that is being combusted in the reformer and is also therefore combusted.


CAS Number: PMTest Method: EPA/OAR Other Test Mthd 27Pollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 9.9500 LB/H Emission Limit 2: 37.9000 T/YR Standard Emission: 0.0027 GRAINS/DSCF Did factors, other then air pollution technology considerations influence the BACT decisions: YCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (A) a high-energy wet scrubber can accommodate the large volume of gas that is generated by the DRI process,

and is insensitive to variations in dust loading. Additionally, the safety aspects of using a wet system provide themost viable scenario for PM10/PM2.5 emissions control from the DRI process, by cleaning the top gas fuelstream prior to combustion. Nucor will also maintain good combustion practices at the reformer for particulatecontrol of the natural gas combustion, but these actions are not likely to significantly contribute to the control ofPM10 emissions due to the inorganic nature of topgas.

Est. % Efficiency: 99.000Compliance Verified: YesPollutant/Compliance Notes: The top gas contains incombustible particulate matter in the stream as it leaves the shaft furnace. This particulate

would pass through the combustion zone and be emitted in the reformer flue gas if left untreated.


CAS Number: 10102Test Method: EPA/OAR Mthd 7EPollutant Group(s): ( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) ) Emission Limit 1: 10.8800 LB/H Emission Limit 2: 41.4500 T/YR Standard Emission: 0.0070 LB/MMBTU Did factors, other then air pollution technology considerations influence the BACT decisions: YCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (B) The low NOX combustion qualities of top gas fuel are inherent in the DRI reforming process. Additionally,

Control Method: (B) The low NOX combustion qualities of top gas fuel are inherent in the DRI reforming process. Additionally,low-NOX burners may be used with the boosted heating value of top gas mixed with natural gas, without undulypenalizing combustion efficiency. Finally, SCR may be applied to the resulting flue gas stream from combustionin the reformer. Therefore, BACT is selected to be low NOX fuel combustion, combined with low NOX burnersand selective catalytic reduction.

Est. % Efficiency: 90.000Compliance Verified: YesPollutant/Compliance Notes:


CAS Number: VOCTest Method: EPA/OAR Mthd 25APollutant Group(s): ( Volatile Organic Compounds (VOC) ) Emission Limit 1: 8.3800 LB/H Emission Limit 2: 12.2100 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (P) good combustion practicesEst. % Efficiency: 98.000Compliance Verified: YesPollutant/Compliance Notes:


CAS Number: 630-08-0Test Method: EPA/OAR Mthd 10Pollutant Group(s): ( InOrganic Compounds ) Emission Limit 1: 62.1800 LB/H Emission Limit 2: 236.8600 T/YR Standard Emission: 0.0400 LB/MMBTU Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (P) good combustion practices



CAS Number: 7446-09-5Test Method: OtherOther Test Method: Method 8Pollutant Group(s): ( InOrganic Compounds , Oxides of Sulfur (SOx) ) Emission Limit 1: 3.1600 LB/H Emission Limit 2: 11.5000 T/YR Standard Emission: 0.0020 LB/MMBTU Did factors, other then air pollution technology considerations influence the BACT decisions: YCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (A) BACT is selected to be the removal of hydrogen sulfide from the top gas fuel through acid gas scrubbing.

This technology was identified as the most stringent control method of the available technologies, and has theadded benefit of slightly reducing energy demand at the reformer. Nucor will install and acid gas scrubbingsystem for top gas prior to its use as fuel in the reformer. BACT for natural gas is to purchase natural gascontaining no more than 2000 grains of Sulfur per MM scf.

Est. % Efficiency: 95.000Compliance Verified: YesPollutant/Compliance Notes: Method 8 - Determination of Sulfuric Acid Mist and Sulfur Dioxide Emissions from Stationary Sources.

Emissions of SO2 are usually attributable to the sulfur contained within the fuel being combusted. Therefore theuse of a low sulfur fuel can drastically reduce emissions of SO2 when compared to other potential fuels. Sweetnatural gas is often cited as an alternative to other fuels due to the very low sulfur content of this fuel Thereformer also burns top gas from the shaft furnace, which contains a small portion of hydrogen sulfideoriginating from sulfur compounds in the iron ore, as well as any sulfur that was in the natural gas converted intoreformer gas. Once combusted, this hydrogen sulfide converts directly to SO2. Because sulfur is rarelyintroduced into a combustion reaction other than as a component of the fuel, Nucor evaluated both fuel treatmentfor the removal of hydrogen sulfide and other sulfur compounds, as well as flue gas desulfurization (FGD) forthe removal of SO2 from the products of combustion in the flue gas.


CAS Number: 124-38-9Test Method: UnspecifiedPollutant Group(s): ( Acid Gasses/Mist , Greenhouse Gasses (GHG) , InOrganic Compounds )

Emission Limit 1: 11.7900 MMBTU/TON OF DRI Emission Limit 2: Standard Emission: 11.7900 MMBTU/TON OF DRI Did factors, other then air pollution technology considerations influence the BACT decisions: YCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (B) the best available technology for controlling CO2e emissions from the DRI Reformer is good combustion

practices, the Acid gas separation system, and Energy integration. BACT shall be good combustion practices,which will be adhered to maintain low levels of fuel consumption by the LNB burners.

Est. % Efficiency:Compliance Verified: YesPollutant/Compliance Notes: Due to production rate and product quality variability in any production process, production rates should be

inclusive of all production at the facility, both of regular and off-spec materials. Additionally, natural gas isconsumed in the DRI process as both a raw material (for the formation of reducing gas) and as a fuel (for heatingto reaction temperatures). All sources of natural gas consumption at the Reformer should be included in theanalysis. BACT is no more than 13 decatherms of natural gas per tonne of DRI (11.79 MM Btu/ton of DRI).Compliance with the BACT limit shall be determined on the basis of total natural gas consumption, divided bytotal production (including regular and off-spec DRI product) of the facility on a 12-month rolling average.


PROCESSNAME:

DRI-208 - DRI Unit #2 Reformer Main Flue Stack

ProcessType:

81.200 (Steel Production (excludes Steel & Iron Foundry Processes))

PrimaryFuel:

Iron ore and Natural Gas


ProcessNotes:

The Direct Reduction Iron process consists of two main components, a Reformer and the DRI reactor. Natural gas passes through special catalyst tubeswhere the natural gas dissociates into a reducing gas rich in carbon monoxide and hydrogen, which are the primary chemicals used to remove the oxygenfrom the iron ore. The reducing gas is fed in from the bottom of the DRI Reactor. The gas flows countercurrent to the descending iron ore pellets. At thetop of the reactor, the partially spent reducing gas exits and is recompressed, enriched with natural gas, preheated, and transported back to the gasreformer. The reformer reforms the mixture back to 95% hydrogen plus carbon monoxide, which is then ready for re-use by the direct reduction furnace.Some of the reducing gas that has already passed over the iron ore in the DRI reactor (the spent reducing gas is also known as top gas) is mixed with thenatural gas that is being combusted in the reformer and is also therefore combusted.


CAS Number: PM

Test Method: EPA/OAR Other Test Mthd 27Pollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 9.9500 LB/H Emission Limit 2: 37.9000 T/YR Standard Emission: 0.0027 GRAINS/DSCF Did factors, other then air pollution technology considerations influence the BACT decisions: YCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (A) a high-energy wet scrubber can accommodate the large volume of gas that is generated by the DRI process,

and is insensitive to variations in dust loading. Additionally, the safety aspects of using a wet system provide themost viable scenario for PM10/PM2.5 emissions control from the DRI process, by cleaning the top gas fuelstream prior to combustion. Nucor will also maintain good combustion practices at the reformer for particulatecontrol of the natural gas combustion, but these actions are not likely to significantly contribute to the control ofPM10 emissions due to the inorganic nature of topgas.

Est. % Efficiency: 99.000Compliance Verified: YesPollutant/Compliance Notes: The top gas contains incombustible particulate matter in the stream as it leaves the shaft furnace. This particulate

would pass through the combustion zone and be emitted in the reformer flue gas if left untreated.


CAS Number: 10102Test Method: EPA/OAR Mthd 7EPollutant Group(s): ( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) ) Emission Limit 1: 10.8800 LB/H Emission Limit 2: 41.4500 T/YR Standard Emission: 0.0070 LB/MMBTU Did factors, other then air pollution technology considerations influence the BACT decisions: YCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (B) The low NOX combustion qualities of top gas fuel are inherent in the DRI reforming process. Additionally,

low-NOX burners may be used with the boosted heating value of top gas mixed with natural gas, without undulypenalizing combustion efficiency. Finally, SCR may be applied to the resulting flue gas stream from combustionin the reformer. Therefore, BACT is selected to be low NOX fuel combustion, combined with low NOX burnersand selective catalytic reduction.



CAS Number: VOCTest Method: EPA/OAR Mthd 25APollutant Group(s): ( Volatile Organic Compounds (VOC) ) Emission Limit 1: 8.3800 LB/H Emission Limit 2: 12.2100 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (P) good combustion practicesEst. % Efficiency: 98.000Compliance Verified: YesPollutant/Compliance Notes:


CAS Number: 630-08-0Test Method: EPA/OAR Mthd 10Pollutant Group(s): ( InOrganic Compounds ) Emission Limit 1: 62.1800 LB/H Emission Limit 2: 236.8600 T/YR Standard Emission: 0.0040 LB/MMBTU Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (P) good combustion practicesEst. % Efficiency: 98.000Compliance Verified: YesPollutant/Compliance Notes:


CAS Number: 7446-09-5Test Method: Other

Other Test Method: Method 8Pollutant Group(s): ( InOrganic Compounds , Oxides of Sulfur (SOx) ) Emission Limit 1: 3.1600 LB/H Emission Limit 2: 11.5000 T/YR Standard Emission: 0.0020 LB/MMBTU Did factors, other then air pollution technology considerations influence the BACT decisions: YCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (A) BACT is selected to be the removal of hydrogen sulfide from the top gas fuel through acid gas scrubbing.

This technology was identified as the most stringent control method of the available technologies, and has theadded benefit of slightly reducing energy demand at the reformer. Nucor will install and acid gas scrubbingsystem for top gas prior to its use as fuel in the reformer. BACT for natural gas is to purchase natural gascontaining no more than 2000 grains of Sulfur per MM scf.

Est. % Efficiency: 95.000Compliance Verified: YesPollutant/Compliance Notes: Method 8 - Determination of Sulfuric Acid Mist and Sulfur Dioxide Emissions from Stationary Sources.

Emissions of SO2 are usually attributable to the sulfur contained within the fuel being combusted. Therefore theuse of a low sulfur fuel can drastically reduce emissions of SO2 when compared to other potential fuels. Sweetnatural gas is often cited as an alternative to other fuels due to the very low sulfur content of this fuel Thereformer also burns top gas from the shaft furnace, which contains a small portion of hydrogen sulfideoriginating from sulfur compounds in the iron ore, as well as any sulfur that was in the natural gas converted intoreformer gas. Once combusted, this hydrogen sulfide converts directly to SO2. Because sulfur is rarelyintroduced into a combustion reaction other than as a component of the fuel, Nucor evaluated both fuel treatmentfor the removal of hydrogen sulfide and other sulfur compounds, as well as flue gas desulfurization (FGD) forthe removal of SO2 from the products of combustion in the flue gas.


CAS Number: 124-38-9Test Method: UnspecifiedPollutant Group(s): ( Acid Gasses/Mist , Greenhouse Gasses (GHG) , InOrganic Compounds ) Emission Limit 1: 11.7900 MMBTU/TON OF DRI Emission Limit 2: Standard Emission: 11.7900 MMBTU/TON OF DRI Did factors, other then air pollution technology considerations influence the BACT decisions: YCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (B) the best available technology for controlling CO2e emissions from the DRI Reformer is good combustion

Control Method: (B) the best available technology for controlling CO2e emissions from the DRI Reformer is good combustionpractices, the Acid gas separation system, and Energy integration. BACT shall be good combustion practices,which will be adhered to maintain low levels of fuel consumption by the LNB burners.

Est. % Efficiency:Compliance Verified: YesPollutant/Compliance Notes: Due to production rate and product quality variability in any production process, production rates should be

inclusive of all production at the facility, both of regular and off-spec materials. Additionally, natural gas isconsumed in the DRI process as both a raw material (for the formation of reducing gas) and as a fuel (for heatingto reaction temperatures). All sources of natural gas consumption at the Reformer should be included in theanalysis. BACT is no more than 13 decatherms of natural gas per tonne of DRI (11.79 MM Btu/ton of DRI).Compliance with the BACT limit shall be determined on the basis of total natural gas consumption, divided bytotal production (including regular and off-spec DRI product) of the facility on a 12-month rolling average.


RBLC ID: TX-0550 (final) Date DeterminationLast Updated: 05/26/2010

Corporate/Company Name: BASF FINA PETROCHEMICALS LIMITED PARTNERSHIP Permit Number: 36644

Facility Name: BASF FINA NAFTA REGION OLEFINS COMPLEX Permit Date: 02/10/2010 (actual)

Facility Contact: JOHN LYCAN 4099605221 [email protected] FRS Number: 110006134691

Facility Description: OLEFINS COMPLEX, ETHYLENE CRACKING FACILITY SIC Code: 2869

Permit Type: A: New/Greenfield Facility NAICS Code: 325131


Facility County: JEFFERSON

Facility State: TX

Facility ZIP Code: 77643-506

Permit Issued By: EPA REGION VI (Agency Name) MR. RICHARD A. BARRETT(Agency Contact) (214) 665-7227 [email protected]

Other Agency Contact Info: TCEQ AIR PERMITTING DEPARTMENT (APD)PROJECT ENGINEER: DANIEL SMOTHERS: DIRECT (512) 239-1664 RECEPTIONIST (512)-239-1250

Permit Notes: NO PROCESSES WERE ADDED OR AMENDED HOWEVER CALCULATIONS FOR VARIOUS EPNS WERE REVIEWED ANDREVISED BY THE APPLICANT WHEN THE PERMIT WAS EVALUATED FOR RENEWAL. AN EMISSIONS RECALCULATIONRESULTED IN ANNUAL CO EMISSIONS INCREASE AT EPNS N-10, N-11, AND N-18 AND A PSD AMENDMENT. CODECREASED AT EPN N-13 AND VOC INCREASED AT EPNS N-10, N-11, N-19, F-1, AND F-5 AS WELL AS AN INCREASE INNH3 EMISSIONS AT EPN N-23 THAT DID NOT QUALIFY AS A MAJOR MODIFICATION.


PROCESSNAME:

N-10, CATALYST REGENERATION EFFLUENT

ProcessType:

50.003 (Petroleum Refining Conversion Processes (cracking, reforming, etc.))

PrimaryFuel:

METHANE

Throughput: 2100.00 CFS

ProcessNotes:

THE RACT/BACT/LAER (RBLC) DATABASE WAS SEARCHED FOR THIS FACILITY TYPE. A MARATHON PETROLEUM DETROITREFINERY CATALYST REGENERATION UNIT AND A BP WEST COAST PRODUCTS CATALYST REGENERATION UNIT USED GOODCOMBUSTION PRACTICES TO MEET BACT. THESE WERE THE ONLY FACILITIES LISTED IN THE RBLC DATABASE FOR THISFACILITY TYPE. GOOD COMBUSTION PRACTICES ARE USED FOR EPN N-10.THE CATALYST FROM THE ACETYLENE CONVERTERMAIN BEDS, ACETYLENE CONVERTER GUARD BED, METHYL ACETYLENE, PROPADIENE CONVERTERS, C4 DIOLEFINHYDROGENATION REACTOR AND FIRST STAGE DIOLEFINS REACTOR IS HEATED AND ANY COKE PRESENT ON THE CATALYST ISCONVERTED TO CO OR CO2. SINCE GOOD COMBUSTION PRACTICES ARE GOOD BUSINESS PRACTICE, NO ADDITIONALCONDITIONS OR MONITORING WERE REQUIRED FOR THIS AMENDMENT.


CAS Number: 124-38-9Test Method: UnspecifiedPollutant Group(s): ( Acid Gasses/Mist , Greenhouse Gasses (GHG) , InOrganic Compounds ) Emission Limit 1: SEE NOTEEmission Limit 2: Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: NO EMISSION LIMITS AVAILABLE


PROCESS N-11, REACTOR REGENERATION EFFLUENT

PROCESSNAME:

N-11, REACTOR REGENERATION EFFLUENT

Process Type: 50.003 (Petroleum Refining Conversion Processes (cracking, reforming, etc.))

Primary Fuel: METHANE

Throughput: 5064.83 CFS

ProcessNotes:

THE RACT/BACT/LAER DATABASE WAS SEARCHED FOR THIS FACILITY TYPE AND NO EXACT PROCESS WAS FOUND. THE MSSPROCESS AT N-11 IS SIMILAR TO N-10, THE CATALYST FROM THE DP REACTOR IS HEATED AND ANY COKE PRESENT ON THECATALYST IS CONVERTED TO CO OR CO2. UNIT USED GOOD COMBUSTION PRACTICES TO MEET BACT SINCE GOOD COMBUSTIONPRACTICES ARE GOOD BUSINESS PRACTICE, NO ADDITIONAL CONDITIONS OR MONITORING WERE REQUIRED FOR THISAMENDMENT.




PROCESSNAME:

N-18, DECOKING DRUM

Process Type: 50.003 (Petroleum Refining Conversion Processes (cracking, reforming, etc.))

Primary Fuel: METHANE

Throughput: 26625.00 LB COKE/CYCLE

Process THE RACT/BACT/LAER DATABASE WAS SEARCHED FOR THIS FACILITY TYPE AND SIMILAR PROCESSES WERE FOUND BUT

ProcessNotes:

THE RACT/BACT/LAER DATABASE WAS SEARCHED FOR THIS FACILITY TYPE AND SIMILAR PROCESSES WERE FOUND BUTTHERE WERE NO PROJECT NOTES. THE DECOKING DRUM AND FURNACE TUBES ARE HEATED AND ANY COKE PRESENT ON THECATALYST IS CONVERTED TO CO OR CO2. UNIT USED GOOD COMBUSTION PRACTICES TO MEET BACT. SINCE GOODCOMBUSTION PRACTICES ARE GOOD BUSINESS PRACTICE, NO ADDITIONAL CONDITIONS OR MONITORING WERE REQUIRED FORTHIS AMENDMENT.




RBLC ID: OK-0135 (final) Date DeterminationLast Updated: 02/18/2010

Corporate/Company Name: PRYOR PLANT CHEMICAL COMPANY Permit Number: 2008-100-C PSD

Facility Name: PRYOR PLANT CHEMICAL Permit Date: 02/23/2009 (actual)

Facility Contact: FRS Number: 4009700008

Facility Description: SIC Code: 2873

Permit Type: C: Modify process at existing facility NAICS Code: 325311


Facility County: MAYES

Facility State: OK


Permit Issued By: OKLAHOMA DEPARTMENT OF ENVIRONMENTAL QUALITY (Agency Name) MR. JERRY GOOCHEY(Agency Contact) (405)702-4189 [email protected]

Permit Notes: PRYOR PLANT CHEMICAL COMPANY (PPCC) SUBMITTED AN APPLICATION DATED MARCH 27, 2008 TO AIR QUALITYDIVISION (AQD) WITH THE REQUIRED FEE OF $2,000 FOR A CONSTRUCTION PERMIT TO PLACE INTO OPERATION ASYNTHETIC FERTILIZER MANUFACTURING PLANT (SIC 2873) THAT HAS BEEN SHUT DOWN FOR APPROXIMATELYTEN YEARS. RATHER THAN ATTEMPT TO RECONCILE EXISTING PERMITS WITH CHANGES THAT MAY RESULT FROMRE-STARTING A PLANT THAT HAS BEEN INACTIVE FOR TEN YEARS TO EVALUATE WHERE SIGNIFICANTMODIFICATIONS ARE OCCURRING, A DECISION TO SIMPLIFY THE PERMITTING PROCESS WAS MADE BY THEAPPLICANT AND ACCEPTED BY AQD. A FULL PSD (PREVENTION OF SIGNIFICANT DETERIORATION) ANALYSIS HASBEEN COMPLETED FOR THIS PERMIT ISSUANCE. IN ADDITION, EVALUATION OF COMPLIANCE ASSURANCEMONITORING (CAM) IS REQUIRED.


PROCESS NAME: PRIMARY REFORMER

Process Type: 61.012 (Fertilizer Production (except 61.009))


Throughput: 700.00 Tons per Day

Process Notes: THE PRIMARY REFORMER IS A PROCESS HEATER USED IN CONVERTING RAW NATURAL GAS INTO AMMONIA.


CAS Number: 630-08-0Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds ) Emission Limit 1: 18.5000 LB/H 1 HOUR/8 HOUREmission Limit 2: Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: N/A Control Method: (N) NO CONTROLS;GOOD COMBUSTION PRACTICES.Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: 10102Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) ) Emission Limit 1: 11.9300 LB/H 3-HOUR/168-H ROLLING CUMMULATIVEEmission Limit 2: 0.2000 LB/MMBTU STATE LIMITStandard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: N/A Control Method: (P) LOW NOX BURNERS/GOOD COMBUSTION PRACTICE.Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:

POLLUTANT NAME: Particulate matter, total (TPM)

CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 1.6800 LB/H Emission Limit 2: Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: N/A Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:



Emission Limit 2: Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: N/A Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: 7446-09-5Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Sulfur (SOx) ) Emission Limit 1: 1.3500 LB/H Emission Limit 2: 0.2000 LB/MMBTU Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: N/A Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: VOCTest Method: UnspecifiedPollutant Group(s): ( Volatile Organic Compounds (VOC) ) Emission Limit 1: 1.2100 LB/H Emission Limit 2: Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSD

Other Applicable Requirements: N/A Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


PROCESS NAME: CONDENSATE STEAM FLASH DRUM-AMMONIA PLT 4

Process Type: 61.999 (Other Agricultural Chemical Manufacturing Sources)

Primary Fuel: Throughput: 80.00 T/H

Process Notes: FLASH DRUM IS A CONTROL DEVICE FOR THE CONDENSATE KNOCKOUT DRUMTO MINIMIZE AMMONIA EMISSIONS.


CAS Number: VOCTest Method: UnspecifiedPollutant Group(s): ( Volatile Organic Compounds (VOC) ) Emission Limit 1: 9.2100 LB/H 1-HOUR AVEmission Limit 2: Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: N/A Control Method: (A) GOOD OPERATION PRACTICESEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: PROPER OPERATION AND MONITORING TO MINIMIZE EMISSIONS.

POLLUTANT NAME: Methanol

CAS Number: 67-56-1Test Method: UnspecifiedPollutant Group(s): ( Hazardous Air Pollutants (HAP) , Organic Compounds (all) , Volatile Organic Compounds (VOC) ) Emission Limit 1: 3.4200 LB/H 1-HR AV

Emission Limit 2: Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: N/A Control Method: (A) GOOD OPERATION PRACTICESEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: PROPER OPERATION AND MONITORING TO MINIMIZE EMISSIONS.

POLLUTANT NAME: Ammonia (NH3)

CAS Number: 7664-41-7Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds ) Emission Limit 1: 0.8000 LB/H 1-HOUR AVEmission Limit 2: Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: N/A Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


PROCESS NAME: NITRIC ACID PLANT #1

Process Type: 62.014 (Nitric Acid Plants)

Primary Fuel: Throughput: 8.30 LB/H

Process Notes:


CAS Number: 10102Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) ) Emission Limit 1: 1.6000 LB/T ANNUALEmission Limit 2: 3.0000 LB/T 7-DAY MAXStandard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: N/A Control Method: (A) EXTENDED ABSORPTION WITH NSCR.Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: NOX LIMIT OF 58.2 T/YR





Process Notes:


CAS Number: 10102Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) ) Emission Limit 1: 1.6000 LB/T ANNUALEmission Limit 2: 3.0000 LB/T 7-DAY MAXStandard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: N/A Control Method: (A) EXTENDED ABSORPTION WITH NSCR AND GOOD OPERATION PRACTICES.Est. % Efficiency:

Compliance Verified: UnknownPollutant/Compliance Notes: NOX LIMIT OF 44.2 TPY.





Process Notes:


CAS Number: 10102Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) ) Emission Limit 1: 2.5000 LB/T ANNUALEmission Limit 2: 3.0000 LB/T 7-DAY MAXStandard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: N/A Control Method: (A) SCR AND GOOD OPERATION PRACTICES.Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: NOX LIMIT OF 159.9 TPY.


PROCESSNAME:

NITRIC ACID PREHEATERS #1, #3, AND #4



Throughput: 20.00 MMBTU/H

Process Notes: THE NITRIC ACID PLANT PREHEATERS ARE USED TO PREHEAT THE PROCESS AIR FROM 300 OF TO 500 OF FOR STARTUPPURPOSES. THE PROCESS AIR FLOWS THROUGH TUBES INSIDE THE PREHEATER.


CAS Number: 10102Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) ) Emission Limit 1: 0.9800 LB/H 168-H ROLLING CUMMULATIVEEmission Limit 2: Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: N/A Control Method: (P) LOW-NOX BURNERS AND GOOD COMBUSTION PRACTICES.Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: 630-08-0Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds ) Emission Limit 1: 1.6500 LB/H 1-HOUR/8-HOUREmission Limit 2: Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: N/A Control Method: (N) GOOD COMBUSTION PRACTICES.Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: PM

CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 0.1500 LB/H 24-HEmission Limit 2: Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: N/A Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 0.1500 LB/H 24-HEmission Limit 2: Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: N/A Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: VOCTest Method: UnspecifiedPollutant Group(s): ( Volatile Organic Compounds (VOC) ) Emission Limit 1: 0.1100 LB/H

Emission Limit 2: Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: N/A Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: 7446-09-5Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Sulfur (SOx) ) Emission Limit 1: 0.0300 LB/H Emission Limit 2: Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: N/A Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


PROCESS NAME: CARBON DIOXIDE VENT



Process Notes: 36.5 TONS/H CO2 VENTED LIMIT


CAS Number: 124-38-9Test Method: UnspecifiedPollutant Group(s): ( Acid Gasses/Mist , Greenhouse Gasses (GHG) , InOrganic Compounds ) Emission Limit 1: 3.6500 LB/H 1-HOUR/8-HOUREmission Limit 2: Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: N/A Control Method: (N) GOOD OPERATION PRACTICES.Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


PROCESS NAME: AMMONIUM NITRATE PLANTS #1 AND #2

Process Type: 61.012 (Fertilizer Production (except 61.009))


Process Notes: 23.8 TPH AMMONIUM NITRATE PER PLANT LIMIT.


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 2.1000 LB/H 24-HEmission Limit 2: Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: N/A Control Method: (A) IN-STACK CONDENSERS AND GOOD OPERATION PRACTICESEst. % Efficiency: 80.000

Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 0.1000 LB/H 24-HOURSEmission Limit 2: Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: N/A Control Method: (A) IN-STACK CONDENSERS AND GOOD OPERATION PRACTICESEst. % Efficiency: 80.000Compliance Verified: UnknownPollutant/Compliance Notes:


PROCESS NAME: GRANULATOR SCRUBBERS #1, #2, AND #3



Process Notes: 16.7 TPH DRY AMMONIUM NITRATE PER SCRUBBER LIMIT


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 0.7000 LB/H 24-HOUREmission Limit 2: Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: U

Case-by-Case Basis: BACT-PSDOther Applicable Requirements: N/A Control Method: (A) GOOD OPERATION PRACTICESEst. % Efficiency: 80.000Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 0.7000 LB/H 24-HOUREmission Limit 2: Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: N/A Control Method: (A) GOOD OPERATION PRACTICESEst. % Efficiency: 80.000Compliance Verified: UnknownPollutant/Compliance Notes:


PROCESS NAME: BOILERS #1 AND #2




Process Notes: THE BOILERS WILL PROVIDE THE STEAM NEEDED TO OPERATE THE VARIOUS PIECES OF EQUIPMENT AT THE FACILITY.



Emission Limit 1: 0.5000 LB/H 24-HOUREmission Limit 2: Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: N/A Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 0.6000 LB/H Emission Limit 2: Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: N/A Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: 7446-09-5Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Sulfur (SOx) ) Emission Limit 1: 0.2000 LB/H Emission Limit 2: 0.2000 LB/MMBTU STATE LIMITStandard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: U

Case-by-Case Basis: BACT-PSDOther Applicable Requirements: N/A Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: VOCTest Method: UnspecifiedPollutant Group(s): ( Volatile Organic Compounds (VOC) ) Emission Limit 1: 0.5000 LB/H Emission Limit 2: Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: N/A Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:

POLLUTANT NAME: Formaldehyde

CAS Number: 50-00-0Test Method: UnspecifiedPollutant Group(s): ( Hazardous Air Pollutants (HAP) , Organic Compounds (all) , Volatile Organic Compounds (VOC) ) Emission Limit 1: 0.1000 LB/H Emission Limit 2: Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: N/A Control Method: (N) Est. % Efficiency:



CAS Number: 10102Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) ) Emission Limit 1: 4.0000 LB/H 3-H/168-H ROLLING CUMMULATIVEEmission Limit 2: 0.2000 LB/MMBTU STATE LIMITStandard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: N/A Control Method: (P) LOW-NOX BURNERS AND GOOD COMBUSTION PRACTICESEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: 630-08-0Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds ) Emission Limit 1: 6.6000 LB/H 1-HOUR/8-HOUREmission Limit 2: Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: N/A Control Method: (N) GOOD COMBUSTION PRACTICESEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


PROCESS NAME: COOLING TOWER #1


Primary Fuel: Throughput: 1.47 MMGAL/H

Process Notes: 1,470,000 GALLONS PER HR CIRCULATION RATE LIMIT


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 1.1800 LB/H 24-HEmission Limit 2: Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: N/A Control Method: (A) MIST ELIMINATORSEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


PROCESS NAME: COOLING TOWER #2


Primary Fuel: Throughput: 2.40 MMGAL/H

Process Notes: 2,400,000 GALLONS PER HR CIRCULATION RATE LIMIT


CAS Number: PMTest Method: Unspecified

Pollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 1.9200 LB/H 24-HOUREmission Limit 2: Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: N/A Control Method: (A) MIST ELIMINATORSEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


RBLC ID: LA-0148 (final) DateDeterminationLast Updated: 11/03/2008


RED RIVER ENVIRONMENTAL PRODUCTS LLC Permit Number: PSD-LA-727

Facility Name: ACTIVATED CARBON FACILITY Permit Date: 05/28/2008 (actual)

Facility Contact: C JEAN BUSTARD 3037341727 FRS Number: 110031155853

Facility Description: THE FACILITY WILL USE COAL AS A FEEDSTOCK TO MANUFACTURE ROUGHLY 350MILLION POUNDS OF ACTIVATED CARBON (AC) PER YEAR.

SIC Code: 2819



Facility County: RED RIVER

Facility State: LA



Permit Notes:


PROCESSNAME:

MULTIPLE HEARTH FURNACES / AFTERBURNERS

Process Type: 11.110 (Coal (includes bituminous, subbituminous, anthracite, and lignite))

Primary Fuel: COAL

Throughput: 7.78 LB/YR E +08

Process Notes: 4 MULTI-HEARTH FURNACES. PROCESSES LIGNITE COAL. ALSO COMBUSTS 13.2 MM BTU /HR NATURAL GAS TO BALANCEHEAT LOADS.


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 48.3000 LB/H 3-HOUREmission Limit 2: Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements: NSPS , OPERATING PERMIT , OTHER Control Method: (A) CYCLONE, AFTERBURNER, SDA SYSTEM AND FABRIC FILTER BAGHOUSEEst. % Efficiency: 99.900Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: 124-38-9Test Method: UnspecifiedPollutant Group(s): ( Acid Gasses/Mist , Greenhouse Gasses (GHG) , InOrganic Compounds ) Emission Limit 1: 37.6000 LB/H 3-HOUREmission Limit 2: Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: NSPS , SIP , OPERATING PERMIT , OTHER Control Method: (A) AFTERBURNER AND GOOD COMBUSTION PRACTICES



CAS Number: VOCTest Method: UnspecifiedPollutant Group(s): ( Volatile Organic Compounds (VOC) ) Emission Limit 1: 35.9000 LB/H Emission Limit 2: Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: NSPS , SIP , OPERATING PERMIT , OTHER Control Method: (A) AFTERBURNER AND GOOD COMBUSTION PRACTICESEst. % Efficiency: 99.900Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: 10102Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) ) Emission Limit 1: 77.3000 LB/H (12-MO. ROLLING)Emission Limit 2: Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: NSPS , SIP , OPERATING PERMIT , OTHER Control Method: (A) COMBUSTION CONTROLS (INCLUDING LOW-NOX BURNERS) AND SNCREst. % Efficiency: 50.000Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: 7446-09-5Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Sulfur (SOx) ) Emission Limit 1: 101.2000 LB/H (30-DAY ROLLING)Emission Limit 2: Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: NSPS , SIP , OPERATING PERMIT , OTHER Control Method: (A) SPRAY DRYER ABSORBER (SDA) SYSTEMEst. % Efficiency: 92.000Compliance Verified: UnknownPollutant/Compliance Notes:

POLLUTANT NAME: Sulfuric Acid (mist, vapors, etc)

CAS Number: 7664-93-9Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Particulate Matter (PM) ) Emission Limit 1: 1.5500 LB/H (3-HR AVG.)Emission Limit 2: Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: NSPS , SIP , OPERATING PERMIT , OTHER Control Method: (A) SDA SYSTEM AND FABRIC FILTER BAGHOUSEEst. % Efficiency: 92.000Compliance Verified: UnknownPollutant/Compliance Notes:


PROCESS NAME: COOLING TOWERS


Primary Fuel: Throughput: 10750.00 GAL/MIN

Process Notes:


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 0.4100 LB/H Emission Limit 2: Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: SIP , OPERATING PERMIT Control Method: (P) DRIFT ELIMINATION SYSTEMEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


RBLC ID: AL-0231 (final) DateDeterminationLast Updated: 08/31/2009


NUCOR CORPORATION Permit Number: 712-0037

Facility Name: NUCOR DECATUR LLC Permit Date: 06/12/2007 (actual)

Facility Contact: JEFF BROWN 2563013508 [email protected] FRS Number: 110000589328

Facility Description: THE FACILITY PRODUCES STEEL COILS PRIMARILY FROM STEEL SCRAP USING THEELECTRIC ARC FURNACE (EAF) PROCESS.

SIC Code: 3312

Permit Type: D: Both B (Add new process to existing facility) &C (Modify process at existing facility) NAICS Code: 331111


Facility County: MORGAN

Facility State: AL


Permit Issued By: ALABAMA DEPT OF ENVIRONMENTAL MGMT (Agency Name) MR. ANTHONY SMILEY(Agency Contact) (334) 271-7714 [email protected]

Other Agency ContactInfo:

PLEASE SEND ANY QUESTIONS TO CHARLES KILLEBREW, ADEM PERMIT ENGINEER, AT 334-270-5675.

Permit Notes: FACILITYWIDE EMISSIONS CONTINUED: PB - 1.5 T/YR


PROCESSNAME:

TWO (2) ELECTRIC ARC FURNACES AND THREE (3) LADLE METALLURGY FURNACES WITH TWO (2) MELTSHOP BAGHOUSES

Process Type: 81.210 (Electric Arc Furnaces)

Primary Fuel: ELECTRICITY

Throughput: 440.00 T/H

Process Notes:


CAS Number: 10102Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) ) Emission Limit 1: 0.4200 LB/T Emission Limit 2: 184.8000 LB/H Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: VOC

Test Method: UnspecifiedPollutant Group(s): ( Volatile Organic Compounds (VOC) ) Emission Limit 1: 0.1300 LB/T Emission Limit 2: 57.2000 LB/H Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: 630-08-0Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds ) Emission Limit 1: 2.3000 LB/T Emission Limit 2: 1012.0000 LB/H Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:

POLLUTANT NAME: Lead (Pb) / Lead Compounds

CAS Number: 7439-92-1Test Method: UnspecifiedPollutant Group(s): ( Hazardous Air Pollutants (HAP) , Heavy Metals , InOrganic Compounds , Particulate Matter (PM) ) Emission Limit 1: 0.0020 LB/T Emission Limit 2:

Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (A) TWO (2) MELTSHOP BAGHOUSES WITH DIRECT EVACUATION CANOPIESEst. % Efficiency: 99.000Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 0.0018 GR/DSCF Emission Limit 2: 43.2200 LB/H Standard Emission: 0.0018 GR/DSCF Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements: NSPS , OPERATING PERMIT Control Method: (A) TWO MELTSHOP BAGHOUSES WITH DIRECT EVACUATION CANOPIESEst. % Efficiency: 99.000Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: 7446-09-5Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Sulfur (SOx) ) Emission Limit 1: 0.6200 LB/T Emission Limit 2: 220.0000 LB/H Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements:

Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


PROCESS NAME: VACUUM DEGASSER BOILER




Process Notes:


CAS Number: 10102Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) ) Emission Limit 1: 0.0350 LB/MMBTU Emission Limit 2: 3.3300 LB/H Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (P) ULTRA LOW NOX BURNERSEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: 124-38-9Test Method: UnspecifiedPollutant Group(s): ( Acid Gasses/Mist , Greenhouse Gasses (GHG) , InOrganic Compounds ) Emission Limit 1: 0.0610 LB/MMBTU Emission Limit 2: 5.8000 LB/H

Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: YCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: 7446-09-5Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Sulfur (SOx) ) Emission Limit 1: 0.0006 LB/MMBTU Emission Limit 2: 0.0570 LB/H Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: VOCTest Method: UnspecifiedPollutant Group(s): ( Volatile Organic Compounds (VOC) ) Emission Limit 1: 0.0026 LB/MMBTU Emission Limit 2: 0.2500 LB/H Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:


POLLUTANT NAME: Particulate Matter (PM)

CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 0.0076 LB/MMBTU Emission Limit 2: 0.7200 LB/H Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


PROCESS NAME: GALVANIZING LINE FURNACE




Process Notes:


CAS Number: VOCTest Method: UnspecifiedPollutant Group(s): ( Volatile Organic Compounds (VOC) ) Emission Limit 1: 0.0055 LB/MMBTU Emission Limit 2: 0.5400 LB/H

Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: 7446-09-5Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Sulfur (SOx) ) Emission Limit 1: 0.0006 LB/MMBTU Emission Limit 2: 0.0060 LB/H Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: 630-08-0Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds ) Emission Limit 1: 0.0840 LB/MMBTU Emission Limit 2: 8.3000 LB/H Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:



CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 0.0076 LB/MMBTU Emission Limit 2: 0.7500 LB/H Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: 10102Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) ) Emission Limit 1: 0.0670 LB/MMBTU Emission Limit 2: 6.6000 LB/H Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (A) SCRUBBEREst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


PROCESS NAME: VACUUM DEGASSER



Process Notes:


CAS Number: 7446-09-5Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Sulfur (SOx) ) Emission Limit 1: 0.0050 LB/T Emission Limit 2: 2.2000 LB/H Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 0.0080 GR/DSCF Emission Limit 2: 0.9100 LB/H Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:



CAS Number: VOCTest Method: UnspecifiedPollutant Group(s): ( Volatile Organic Compounds (VOC) ) Emission Limit 1: 0.0050 LB/T Emission Limit 2: 2.2000 LB/H Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: NCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: 630-08-0Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds ) Emission Limit 1: 0.0750 LB/T Emission Limit 2: 33.0000 LB/H Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (A) FLAREEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: 10102Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) ) Emission Limit 1: 0.0050 LB/T Emission Limit 2: 2.2000 LB/H Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


RBLC ID: TX-0481 (final) DateDeterminationLast Updated: 10/01/2007


AIR PRODUCTS LP PermitNumber:

PSD-TX-1044 /35873

Facility Name: AIR PRODUCTS BAYTOWN I I Permit Date: 11/02/2004(actual)

Facility Contact: KATHLEEN BRANDT 2818380202 FRS Number: 110012710423

Facility Description: THIS FACILITY GETS RAW SYNTHESIS GAS FROM EXXON¿S SYNTHESIS GAS MANUFACTURINGUNIT. THE RAW SYNGAS STREAM FROM THE EXXON PLANT, CONSISTING OF CO2, CO, H2, H2S,COS, HCN, NH3 AND METHANE, IS PIPED TO THE AIR PRODUCTS PLANT WHERE THE ACIDGASES AND AMMONIA WILL BE REMOVED BY AIR PRODUCTS¿ RECTISOL UNIT. THE PRODUCTSPRODUCED INCLUDE CO, AND TWO PURE SYNTHESES GAS PRODUCTS. THESE PRODUCTS AREDISTRIBUTED TO CUSTOMERS VIA PIPELINES. AN IMPURE SYNGAS IS ALSO PRODUCED ANDUSED OFFSITE AS FUEL. THE NEW PROCESS WILL CONVERT A PORTION OF THE SYNGAS TOHYDROGEN. THE HYDROGEN WILL BE PURIFIED AND DISTRIBUTED TO CUSTOMERS.

SIC Code: 492


Permit URL:

EPA Region: 6 COUNTRY: USA

Facility County: HARRIS

Facility State: TX


Permit Issued By: TEXAS COMMISSION ON ENVIRONMENTAL QUALITY (TCEQ) (Agency Name) RANDY HAMILTON(Agency Contact) (512) 239-1512 [email protected]

Permit Notes: AIR PRODUCTS REQUESTED AN AMENDMENT TO AUTHORIZE THE ADDITION OF A HYDROGEN PURIFICATION SYSTEM TOTHEIR SYN GAS PRODUCTION FACILITY. THE REQUESTED ADDITIONS INCLUDED: 1) A SHIFT REACTOR TO PRODUCEADDITIONAL HYDROGEN 2) 2 PRESSURE SWING ADSORBERS (PSA¿S) TO PURIFY HYDROGEN 3) A 350 MMBTU/HR BOILER(EPN 7) TO GENERATE STEAM FIRING PSA TAIL GAS . THE BOILER EMITS MORE THAN 100 TPY CO, MAKING THIS PERMIT APSD PROJECT FOR CO, PSD PERMIT NO. P1044. THE COMPANY ALSO INCLUDED THE FOLLOWING PERMIT BY RULES:AUTHORIZATION TYPE NUMBER DESCRIPTION PBR 43611 A DIESEL FUEL TANK (EPN 8), MEETS BACT, SEE SOURCES ANDCONTROLS PBR 43611 A PROCESS STEAM VENT (EPN SVENT1), MEETS BACT, SEE SOURCES AND CONTROLS 106.511 NONE ANEMERGENCY GENERATOR (EPN 9), MEETS BACT, SEE SOURCES AND CONTROLS FINALLY, THE COMPANY AUTHORIZED ASTART UP PROCESS VENT FOR THE SHIFT REACTOR STEAM DRUM. THERE ARE VIRTUALLY NO VOC EMISSIONS FROM THEVENT. THERE WAS A SMALL INCREASE IN FUGITIVE EMISSIONS DUE TO NEW PIPING FOR THE SHIFT REACTOR SYSTEM.


PROCESS NAME: RECTISOL VENT

Process Type: 64.003 (Processes Vents (emissions from air oxidation, distillation, and other reaction vessels))

Primary Fuel: Throughput: Process Notes:


CAS Number: 67-56-1Test Method: UnspecifiedPollutant Group(s): ( Hazardous Air Pollutants (HAP) , Organic Compounds (all) , Volatile Organic Compounds (VOC) ) Emission Limit 1: 1.3000 LB/H Emission Limit 2: 5.7000 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: N/A Control Method: (N)



CAS Number: 630-08-0Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds ) Emission Limit 1: 11.4000 LB/H Emission Limit 2: 0.4700 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: N/A Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:

POLLUTANT NAME: Hydrogen Sulfide

CAS Number: 7783-06-4Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds ) Emission Limit 1: 1.6500 LB/H Emission Limit 2: 7.0200 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements: N/A Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:

POLLUTANT NAME: Carbonyl Sulfide

CAS Number: 463-58-1Test Method: UnspecifiedPollutant Group(s): ( Hazardous Air Pollutants (HAP) , InOrganic Compounds ) Emission Limit 1: 2.9200 LB/H Emission Limit 2: 12.4000 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: N/AOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


PROCESS NAME: FLARE (NORMAL OPERATION)

Process Type: 19.310 (Chemical Plant Flares)


Throughput: Process Notes:


CAS Number: VOCTest Method: UnspecifiedPollutant Group(s): ( Volatile Organic Compounds (VOC) ) Emission Limit 1: 0.0100 LB/H Emission Limit 2: 0.0400 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N)



CAS Number: 10102Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) ) Emission Limit 1: 11.4000 LB/H Emission Limit 2: 0.4700 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: N/AOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: 7446-09-5Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Sulfur (SOx) ) Emission Limit 1: 0.0400 LB/H Emission Limit 2: 0.0500 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: N/AOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: 630-08-0Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds ) Emission Limit 1: 797.7000 LB/H Emission Limit 2: 11.0900 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: N/AOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


PROCESS NAME: MSS-NONCONDENSIBLES (PROPYLENE VENTING)




CAS Number: 10102Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) ) Emission Limit 1: 2.5200 LB/H Emission Limit 2: 0.0200 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: N/AOther Applicable Requirements:Control Method: (N)




POLLUTANT NAME: Propylene

CAS Number: 115-07-1Test Method: UnspecifiedPollutant Group(s): ( Organic Compounds (all) , Organic Non-HAP Compounds ) Emission Limit 1: 20.0000 LB/H Emission Limit 2: 0.1200 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: N/AOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


PROCESS NAME: PARTS WASHER

Process Type: 99.999 (Other Miscellaneous Sources)



CAS Number: VOCTest Method: UnspecifiedPollutant Group(s): ( Volatile Organic Compounds (VOC) ) Emission Limit 1: 0.0200 LB/H Emission Limit 2: 0.1000 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: N/AOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


PROCESS NAME: FUGITIVES (4)

Process Type: 50.007 (Petroleum Refining Equipment Leaks/Fugitive Emissions)

Primary Fuel: Throughput: Process Notes: THE CO EMISSIONS ARE ELIGIBLE FOR PSD


CAS Number: VOCTest Method: Unspecified

Test Method: UnspecifiedPollutant Group(s): ( Volatile Organic Compounds (VOC) ) Emission Limit 1: 0.2300 LB/H Emission Limit 2: 1.0100 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: N/AOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:



POLLUTANT NAME: Hydrogen Sulfide

CAS Number: 7783-06-4Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds ) Emission Limit 1: 0.3800 LB/H Emission Limit 2: 1.6400 T/YR

Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: N/AOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:

POLLUTANT NAME: Carbonyl Sulfide

CAS Number: 463-58-1Test Method: UnspecifiedPollutant Group(s): ( Hazardous Air Pollutants (HAP) , InOrganic Compounds ) Emission Limit 1: 0.0200 LB/H Emission Limit 2: 0.0900 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: N/AOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:

POLLUTANT NAME: Hydrogen Cyanide

CAS Number: 74-90-8Test Method: UnspecifiedPollutant Group(s): ( Hazardous Air Pollutants (HAP) , Organic Compounds (all) , Organic Non-HAP Compounds ) Emission Limit 1: 0.0100 LB/H Emission Limit 2: 0.0100 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: N/AOther Applicable Requirements:



CAS Number: 115-07-1Test Method: UnspecifiedPollutant Group(s): ( Organic Compounds (all) , Organic Non-HAP Compounds ) Emission Limit 1: 0.3900 LB/H Emission Limit 2: 1.7000 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: N/AOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: 67-56-1Test Method: UnspecifiedPollutant Group(s): ( Hazardous Air Pollutants (HAP) , Organic Compounds (all) , Volatile Organic Compounds (VOC) ) Emission Limit 1: 0.8100 LB/H Emission Limit 2: 3.5400 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: N/AOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


PROCESS NAME: COOLING TOWER

Process Type: 50.005 (Petroleum Refining Separation Processes (distillation and light ends recovery))



CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 1.3600 LB/H Emission Limit 2: 5.9600 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: N/AOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


PROCESS NAME: SUPPLEMENTARY COOLING TOWER

Process Type: 50.005 (Petroleum Refining Separation Processes (distillation and light ends recovery))



CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 0.3400 LB/H Emission Limit 2: 1.4900 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: N/AOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


PROCESS NAME: BOILER STACK

Process Type: 11.390 (Other Gaseous Fuel & Gaseous Fuel Mixtures)


Throughput: Process Notes: CO EMISSIONS ARE ELIGIBLE FOR PSD


CAS Number: 630-08-0Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds ) Emission Limit 1: 28.3000 LB/H Emission Limit 2: 123.8000 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: N/AOther Applicable Requirements:Control Method: (N) Est. % Efficiency:



CAS Number: 10102Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) ) Emission Limit 1: 6.0000 LB/H Emission Limit 2: 9.2100 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: N/AOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: 7446-09-5Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Sulfur (SOx) ) Emission Limit 1: 24.2000 LB/H Emission Limit 2: 9.9400 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: N/AOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:







Emission Limit 2: 11.4300 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: N/AOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


PROCESS NAME: BOILER STACK (HIGH BTU FUEL)




CAS Number: 10102Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) ) Emission Limit 1: 21.0000 LB/H Emission Limit 2: Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: N/AOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


PROCESS NAME: BOILER STACK (START UP)




CAS Number: 10102Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) ) Emission Limit 1: 176.7800 LB/H Emission Limit 2: Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: N/AOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


PROCESS NAME: DIESEL FUEL TANK

Process Type: 42.005 (Petroleum Liquid Storage in Fixed Roof Tanks)




Pollutant Group(s): ( Volatile Organic Compounds (VOC) ) Emission Limit 1: 0.0100 LB/H Emission Limit 2: 0.0100 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: N/AOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:




PROCESS NAME: EMERGENCY GENERATOR

Process Type: 19.800 (Misc. Internal Combustion Engines)

Primary Fuel: Throughput:

Process Notes: CO EMISSIONS ARE ELIGIBLE FOR PSD


CAS Number: 124-38-9Test Method: UnspecifiedPollutant Group(s): ( Acid Gasses/Mist , Greenhouse Gasses (GHG) , InOrganic Compounds ) Emission Limit 1: 2.2400 LB/H Emission Limit 2: 0.9900 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: 10102Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) ) Emission Limit 1: 10.4000 LB/H Emission Limit 2: 4.5600 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: VOC

Test Method: UnspecifiedPollutant Group(s): ( Volatile Organic Compounds (VOC) ) Emission Limit 1: 1.0100 LB/H Emission Limit 2: 0.4600 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: 7446-09-5Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Sulfur (SOx) ) Emission Limit 1: 4.8000 LB/H Emission Limit 2: 2.1100 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 0.7400 LB/H Emission Limit 2: 0.3300 T/YR

Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


PROCESS NAME: EMERGENCY GENERATOR TANK

Process Type: 19.800 (Misc. Internal Combustion Engines)





PROCESS NAME: PROCESS STEAM VENT


Primary Fuel: Throughput: Process Notes: DS




PROCESS NAME: MSS PROCESS STEAM VENT





Emission Limit 1: 0.0100 LB/H Emission Limit 2: 0.0100 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: N/AOther Applicable Requirements:Control Method: (N) Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


RBLC ID: TX-0347 (final) DateDeterminationLast Updated: 08/14/2006


BP AMOCO CHEMICAL COMPANY PermitNumber:

PSD-TX-854

Facility Name: CHOCOLATE BAYOU PLANT Permit Date: 10/16/2001(actual)

Facility Contact: JOEL H. ROBINS 7135813498 FRS Number: 110000606933

Facility Description: BP AMOCO PROPOSES TO INCREASE ITS ETHYLENE PRODUCTION FROM THE NO. 1 AND NO. 2OLEFINS UNITS AT THE CHOCOLATE BAYOU PLANT. TO ACHIEVE THE PRODUCTION INCREASE,BP AMOCO PLANS TO REPLACE THE EXISTING FURNACES AT NO. 1 OLEFINS AND EITHERREPLACE OR RETROFIT THE FURNACES AT THE NO. 2 OLEFINS UNIT. LOW-NOX TECHNOLOGYWILL BE UTILIZED ON THESE FURNACE REPLACEMENTS OR RETROFITS. BP AMOCO ISREQUESTING THIS CONSOLIDATED PERMIT INCLUDE A FLEXIBLE EMISSION CAP FOR ALLCRACKING FURNACES IN NO. 1 AND NO. 2 OLEFINS UNITS AND A FLEXIBLE EMISSION CAP FORTHE EXTERNAL FLOATING ROOF TANKS.

SIC Code: 2869

Permit Type: D: Both B (Add new process to existing facility) &C (Modify process at existing facility) NAICS Code: 325110


Facility County: BRAZORIA

Facility State: TX


Permit Issued By: TEXAS COMMISSION ON ENVIRONMENTAL QUALITY (TCEQ) (Agency Name) RANDY HAMILTON(Agency Contact) (512) 239-1512 [email protected]


ALAN PEGUES PO BOX 13087AUSTIN, TX 78711-3087512-239-1319

Permit Notes: PETROCHEMICAL MANUFACTURING, OLEFINS CRACKING FURNACES


PROCESS NAME: NO.1 OLEFINS COOLING TOWER, AT-1210




CAS Number: VOCTest Method: UnspecifiedPollutant Group(s): ( Volatile Organic Compounds (VOC) ) Emission Limit 1: 4.1400 LB/H Emission Limit 2: 18.1300 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown

Case-by-Case Basis: N/AOther Applicable Requirements: NSPS Control Method: (P) WEEKLY VOC AND BX MONITORING OF THE CIRCULATION WATER.Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:



Emission Limit 1: 2.4700 LB/H Emission Limit 2: 10.8100 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown

Case-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) NONE INDICATEDEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


PROCESS NAME: NO. 2 OLEFINS COOLING TOWER, DAT-3201





Case-by-Case Basis: N/AOther Applicable Requirements: NSPS Control Method: (P) WEEKLY MONITORING OF VOC AND BZ IN THE CIRCULATION WATEREst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 3.2900 LB/H Emission Limit 2: 14.4100 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown



PROCESS NAME: NO. 1 OLEFINS UNIT FUGITIVES, FUG-V10F

Process Type: 64.002 (Equipment Leaks (valves, compressors, pumps, etc.))




Case-by-Case Basis: N/AOther Applicable Requirements: NSPS Control Method: (P) 28VHP LEAK DETECTION AND REPAIR PROGRAM

Est. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: FUGITIVE RATES ARE AN ESTIMATE ONLY AND SHOULD NOT BE CONSIDERED AS A MAXIMUM

ALLOWABLE EMISSION RATE.


PROCESS NAME: NO. 2 OLEFINS UNIT FUGITIVES, FUG-V20F





Case-by-Case Basis: N/AOther Applicable Requirements: NSPS Control Method: (P) 28VHP LDAR PROGRAMEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


PROCESS NAME: NO. 1&2 OLEFINS ANALYZER VENT FUGITIVES



Throughput: Process Notes: FUG-A10F & FUG-A20F


CAS Number: VOCTest Method: UnspecifiedPollutant Group(s): ( Volatile Organic Compounds (VOC) ) Emission Limit 1: 0.0100 LB/H EACH VENTEmission Limit 2: 0.0100 T/YR EACH VENTStandard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown

Case-by-Case Basis: N/AOther Applicable Requirements: NSPS Control Method: (P) 28VHP LDAR PROGRAMEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: FUGITIVE RATES ARE AN ESTIMATE ONLY AND SHOULD NOT CONSIDERED AS A MAXIMUM

ALLOWABLE EMISSION RATE.


PROCESS NAME: SECOND STAGE HYDROTREATER FUGITIVES, FUGVSSH





Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown

Case-by-Case Basis: N/AOther Applicable Requirements: NSPS Control Method: (P) 28VHP LDAR PROGRAMEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: FUGITIVE EMISSIONS ARE AN ESTIMATE ONLY AND SHOULD NOT BE CONSIDERED AS A

MAXIMUM ALLOWABLE EMISSION RATE


PROCESS NAME: TANK FARM FUGITIVES, FUG-FTF





Case-by-Case Basis: N/AOther Applicable Requirements: NSPS Control Method: (P) 28VHP LDAR PROGRAMEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: FUGITIVE EMISSIONS ARE AN ESTIMATE ONLY AND SHOULD NOT BE CONSIDERED AS A



PROCESS NAME: MARINE DOCK FUGITIVES, FUG-VBD





Case-by-Case Basis: N/AOther Applicable Requirements: SIP Control Method: (P) 28VHP LDAR PROGRAMEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: FUGITIVE EMISSIONS ARE AN ESTIMATE ONLY AND SHOULD NOT BE CONSIDERED AS A



PROCESS NAME: METERING STATION FUGITIVES, FUG-VCM




CAS Number: VOC

Test Method: UnspecifiedPollutant Group(s): ( Volatile Organic Compounds (VOC) ) Emission Limit 1: 0.3100 LB/H Emission Limit 2: 1.3800 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown

Case-by-Case Basis: N/AOther Applicable Requirements: SIP Control Method: (P) 28 VHP LDAR PROGRAMEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: FUGITIVE EMISSIONS ARE AN ESTIMATE ONLY AND SHOULD NOT BE CONSIDERED AS A



PROCESS NAME: RAIL LOADING FUGITIVES, FUG-RAIL

Process Type: 64.005 (Transfer of SOCMI Chemicals (loading/unloading, filling, etc.))




Case-by-Case Basis: N/AOther Applicable Requirements: NSPS Control Method: (P) 28 VHP LDAR PROGRAMEst. % Efficiency:Compliance Verified: Unknown



PROCESS NAME: NO. 1 OLEFINS TRUCK LOADING, FUELTRK1





Case-by-Case Basis: N/AOther Applicable Requirements: NSPS Control Method: (N) NONE INDICATEDEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


PROCESS NAME: NO. 2 OLEFINS TRUCK LOADING, FUELTRK2







PROCESS NAME: BLEACH TANK, AF-1215

Process Type: 64.999 (Other SOCMI Processes)


POLLUTANT NAME: Sodium Hypochlorite

CAS Number: 7681-52-9Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds ) Emission Limit 1: 0.0400 LB/H Emission Limit 2: 0.0100 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: Other Case-by-CaseOther Applicable Requirements:Control Method: (N) NONE INDICATED

Control Method: (N) NONE INDICATEDEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: POLLUTANT: NAOCL


PROCESS NAME: BLEACH TANK, AF-3215

Process Type: 64.999 (Other SOCMI Processes)


POLLUTANT NAME: Chlorine / Chlorine Compounds

CAS Number: 7782-50-5Test Method: UnspecifiedPollutant Group(s): ( Acid Gasses/Mist , Hazardous Air Pollutants (HAP) ) Emission Limit 1: 0.0300 LB/H CHLORINE GASEmission Limit 2: 0.0100 T/YR CHLORINE GASStandard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: Other Case-by-CaseOther Applicable Requirements:Control Method: (N) NONE INDICATEDEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


PROCESS NAME: SLOP TANK, AF-3701

Process Type: 64.004 (Storage Tanks (SOCMI only - also see 42.001-42.999 and 62.020))

Primary Fuel:


POLLUTANT NAME: Acetonitrile

CAS Number: 75-05-8Test Method: UnspecifiedPollutant Group(s): ( Hazardous Air Pollutants (HAP) , Organic Compounds (all) ) Emission Limit 1: 0.6100 LB/H Emission Limit 2: 0.0100 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: MACTOther Applicable Requirements: MACT Control Method: (N) NONE INDICATEDEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: POLLUTANT: ACETONITRILE, C2H3N, CAS 75-05-8





PROCESSNAME:

(2) ACETONITRILE TANKS, AF-1103&-1104


Primary Fuel: Throughput: Process Notes: THE PERMIT DOES NOT SPECIFY WHETHER THE TANKS ARE FLOATING OR FIXED ROOFED. THE SCC CODE WAS CHOSEN FOR

PURPOSES OF THIS DATABASE.


CAS Number: 75-05-8Test Method: UnspecifiedPollutant Group(s): ( Hazardous Air Pollutants (HAP) , Organic Compounds (all) ) Emission Limit 1: 0.0600 LB/H EACH TANKEmission Limit 2: 0.1100 T/YR EACH TANKStandard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: MACTOther Applicable Requirements: MACT Control Method: (N) NONE INDICATEDEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: POLLUTANT: ACETONITRILE, C2H3N, CAS 75-05-8


PROCESS NAME: RERUNS BOTTOMS TANK, AF-1105






POLLUTANT NAME: Benzene

CAS Number: 71-43-2Test Method: UnspecifiedPollutant Group(s): ( Hazardous Air Pollutants (HAP) , Organic Compounds (all) , Organic Non-HAP Compounds , Volatile

Organic Compounds (VOC) ) Emission Limit 1: 0.0100 LB/H Emission Limit 2: 0.0100 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown

Case-by-Case Basis: MACTOther Applicable Requirements: MACT Control Method: (N) NONE INDICATEDEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:

POLLUTANT NAME: Toluene

CAS Number: 108-88-3Test Method: UnspecifiedPollutant Group(s): ( Hazardous Air Pollutants (HAP) , Organic Compounds (all) , Volatile Organic Compounds (VOC) ) Emission Limit 1: 0.0100 LB/H




PROCESS NAME: RERUNS BOTTOMS TANK, AF-1106








Organic Compounds (VOC) ) Emission Limit 1: 0.0100 LB/H Emission Limit 2: 0.0100 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown



CAS Number: 108-88-3Test Method: UnspecifiedPollutant Group(s): ( Hazardous Air Pollutants (HAP) , Organic Compounds (all) , Volatile Organic Compounds (VOC) ) Emission Limit 1: 0.0100 LB/H Emission Limit 2: 0.0100 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown



PROCESS NAME: FUEL OIL TANK, AF-1905

Process Type: 42.009 (Volatile Organic Liquid Storage)






PROCESS NAME: ACETONITRILE TANK, AF-3103




CAS Number: 75-05-8Test Method: UnspecifiedPollutant Group(s): ( Hazardous Air Pollutants (HAP) , Organic Compounds (all) ) Emission Limit 1: 0.0600 LB/H Emission Limit 2: 10.0000 T/YR

Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: MACTOther Applicable Requirements: MACT Control Method: (N) NONE INDICATEDEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: POLLUTANT: ACETONITRILE, C2H3N, CAS 75-05-8


PROCESS NAME: FUEL OIL TANK, AF-3905







PROCESS NAME: FUEL OIL TANK, DDF-1001







PROCESS NAME: METHANOL TANK, DDF-1301








PROCESS NAME: METHANOL TANK, DDF-202







PROCESS NAME: SODIUM NITRITE SOLUTION TANK, DDF-701







PROCESS NAME: SODIUM NITRITE SOLUTION TANK, DDF-705





Test Method: UnspecifiedPollutant Group(s): ( Volatile Organic Compounds (VOC) ) Emission Limit 1: 6.5000 LB/H Emission Limit 2: 0.0500 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown



PROCESS NAME: FUEL OIL TANK, DF-1001





Case-by-Case Basis: N/AOther Applicable Requirements: NSPS Control Method: (N) NONE INDICATEDEst. % Efficiency:Compliance Verified: Unknown



PROCESS NAME: ALCOHOL TANK, DF-1301







PROCESSNAME:

LUBE OIL STORAGE, DF-502


Primary Fuel: Throughput: Process Notes: THE PERMIT DOES NOT SPECIFY WHETHER THE TANKS ARE FIXED OR FLOATING ROOF. THE SCC CODE WAS CHOSEN FOR

Process Notes: THE PERMIT DOES NOT SPECIFY WHETHER THE TANKS ARE FIXED OR FLOATING ROOF. THE SCC CODE WAS CHOSEN FORPURPOSES OF THIS DATABASE.





PROCESS NAME: SODIUM NITRITE SOLUTION TANK, DF-701





Case-by-Case Basis: N/A










CAS Number: 75-05-8Test Method: UnspecifiedPollutant Group(s): ( Hazardous Air Pollutants (HAP) , Organic Compounds (all) )

Emission Limit 1: 0.6900 LB/H Emission Limit 2: 0.0600 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: MACTOther Applicable Requirements: MACT Control Method: (N) NONE INDICATEDEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: ACETONITRILE









CAS Number: 75-05-8Test Method: UnspecifiedPollutant Group(s): ( Hazardous Air Pollutants (HAP) , Organic Compounds (all) ) Emission Limit 1: 0.6900 LB/H Emission Limit 2: 0.0100 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: MACTOther Applicable Requirements: MACT Control Method: (N) NONE INDICATEDEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: ACETONITRILE


PROCESSNAME:

LUBE OIL STORAGE


Primary Fuel: Throughput: Process Notes: THE PERMIT DOES NOT SPECIFY WHETHER THE TANKS ARE FIXED OR FLOATING ROOF, THE SCC CODE WAS CHOSEN FOR

PURPOSES OF THIS DATABASE ONLY.



Case-by-Case Basis: N/AOther Applicable Requirements: NSPS

Other Applicable Requirements: NSPS Control Method: (N) NONE INDICATEDEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


PROCESS NAME: DECOKE STACK, DF-101




CAS Number: 630-08-0Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds ) Emission Limit 1: 61.0000 LB/H Emission Limit 2: 12.3000 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown




Emission Limit 2: 0.1800 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown

Case-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (A) CYCLONE SEPARATOREst. % Efficiency: 90.000Compliance Verified: UnknownPollutant/Compliance Notes:





PROCESS NAME: DECOKE STACK, DF-104











Emission Limit 2: 0.4000 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown



PROCESS NAME: DECOKE STACK, DDF-101




CAS Number: 124-38-9Test Method: UnspecifiedPollutant Group(s): ( Acid Gasses/Mist , Greenhouse Gasses (GHG) , InOrganic Compounds ) Emission Limit 1: 36.5000 LB/H Emission Limit 2: 7.2000 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown






PROCESS NAME: DECOKE STACK, DDF-104





Case-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (A) CYCLONE SEPARATOREst. % Efficiency: 90.000






PROCESS NAME: (2) DECOKE STACKS, DF-105 & DDF-105










PROCESS NAME: DOCK FLARE, AM-1500




CAS Number: 10102Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) )


Case-by-Case Basis: Other Case-by-CaseOther Applicable Requirements:Control Method: (N) NONE INDICATEDEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:




POLLUTANT NAME: 1, 3-Butadiene

CAS Number: 106-99-0Test Method: UnspecifiedPollutant Group(s): ( Hazardous Air Pollutants (HAP) , Organic Compounds (all) , Volatile Organic Compounds (VOC) ) Emission Limit 1: 0.0400 LB/H Emission Limit 2: 0.1600 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: U

Case-by-Case Basis: MACTOther Applicable Requirements: MACT Control Method: (A) THE FLARE IS A CONTROL DEVICE FOR BUTADIENEEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: POLLUTANT: BUTADIENE, C4H6, CAS 106-99-0


CAS Number: 115-07-1Test Method: UnspecifiedPollutant Group(s): ( Organic Compounds (all) , Organic Non-HAP Compounds ) Emission Limit 1: 0.0300 LB/H Emission Limit 2: 0.1400 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: MACTOther Applicable Requirements: MACT Control Method: (A) THE FLARE IS A CONTROL FOR PROPYLENEEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: POLLUTANT: PROPYLENE, C3H6, CAS 115-07-1



Case-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) NONE INDICATEDEst. % Efficiency:



PROCESS NAME: (2) HYDROTREATER REGENERATOR STACKS,DD-606&DDD-606







CAS Number: 7446-09-5Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Sulfur (SOx) ) Emission Limit 1: 45.8000 LB/H Emission Limit 2: 3.3000 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown



PROCESS NAME: NO. 1 OLEFINS FLARE, DM-1101





Case-by-Case Basis: N/AOther Applicable Requirements: NSPS Control Method: (N) THE FLARE IS A VOC CONTROLEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:












PROCESS NAME: NO. 2 OLEFINS FLARE, DDM-3101















Case-by-Case Basis: N/AOther Applicable Requirements: NSPS Control Method: (N) THE FLARE IS A VOC CONTROLEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


PROCESS NAME: LIME SILO FILTER VENT, DDZ-902





Case-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) THE FILTER CONTROLS PM10 EMISSIONSEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


PROCESS NAME: LIME SILO FILTER VENT






Case-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) THE FILTER CONTROLS PM10 EMISSIONSEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


PROCESS NAME: SEAL OIL VENTS, OF1SOVENT


Primary Fuel: Throughput: Process Notes: ASSUMED HEAVY LIQUID STREAM PUMP SEALS


CAS Number: VOCTest Method: UnspecifiedPollutant Group(s): ( Volatile Organic Compounds (VOC) ) Emission Limit 1: 0.3000 LB/H Emission Limit 2: 0.1000 T/YR

Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown



PROCESS NAME: RAILROAD LOADING FUGITIVES, RAILLOAD







PROCESS NAME: REGENERATION FURNACE, DB-201

Process Type: 19.600 (Misc. Boilers, Furnaces, Heaters)







Case-by-Case Basis: N/AOther Applicable Requirements: NSPS Control Method: (N) NONE INDICATEDEst. % Efficiency:Compliance Verified: Unknown



CAS Number: 10102Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) ) Emission Limit 1: 5.9000 LB/H Emission Limit 2: 25.6000 T/YR Standard Emission: NOT AVAILABLEDid factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: Other Case-by-CaseOther Applicable Requirements:Control Method: (N) NONE INDICATEDEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 0.3000 LB/H Emission Limit 2: 1.2000 T/YR Standard Emission: NOT AVAILABLEDid factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) NONE INDICATEDEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: 7446-09-5

Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Sulfur (SOx) ) Emission Limit 1: 0.5200 LB/H Emission Limit 2: 0.1100 T/YR Standard Emission: NOT AVAILABLEDid factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: Other Case-by-CaseOther Applicable Requirements:Control Method: (N) NONE INDICATEDEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


PROCESS NAME: REGENERATION HEATER, DB-601




CAS Number: 630-08-0Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds ) Emission Limit 1: 0.2900 LB/H Emission Limit 2: 1.2800 T/YR Standard Emission: NOT AVAILABLEDid factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) NONE INDICATEDEst. % Efficiency:Compliance Verified: Unknown







CAS Number: 7446-09-5

Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Sulfur (SOx) ) Emission Limit 1: 0.0700 LB/H Emission Limit 2: 0.0200 T/YR Standard Emission: NOT AVAILABLEDid factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: Other Case-by-CaseOther Applicable Requirements:Control Method: (N) NONE INDICATEDEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:





PROCESS NAME: REGENERATION HEATER, DDB-201










CAS Number: 124-38-9Test Method: UnspecifiedPollutant Group(s): ( Acid Gasses/Mist , Greenhouse Gasses (GHG) , InOrganic Compounds ) Emission Limit 1: 2.1000 LB/H Emission Limit 2: 9.3000 T/YR Standard Emission: NOT AVAILABLEDid factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) NONE INDICATEDEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:




CAS Number: 7446-09-5Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Sulfur (SOx) ) Emission Limit 1: 0.5000 LB/H

Emission Limit 2: 0.1000 T/YR Standard Emission: NOT AVAILABLEDid factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: Other Case-by-CaseOther Applicable Requirements:Control Method: (N) NONE INDICATEDEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


PROCESS NAME: REGENERATION HEATER, DDB-601




CAS Number: 630-08-0Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds ) Emission Limit 1: 0.2800 LB/H Emission Limit 2: 1.2300 T/YR Standard Emission: NOT AVAILABLEDid factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) NONE INDICATEDEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:






CAS Number: 7446-09-5Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Sulfur (SOx) ) Emission Limit 1: 0.0700 LB/H

Emission Limit 2: 0.0200 T/YR Standard Emission: NOT AVAILABLEDid factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: Other Case-by-CaseOther Applicable Requirements:Control Method: (N) NONE INDICATEDEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:





PROCESS NAME: 2ND STAGE HYDROTREATER FEED HEATER, J-1






CAS Number: 7446-09-5Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Sulfur (SOx) ) Emission Limit 1: 0.0800 LB/H Emission Limit 2: 0.0200 T/YR Standard Emission: NOT AVAILABLEDid factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: Other Case-by-CaseOther Applicable Requirements:Control Method: (N) NONE INDICATEDEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


CAS Number: 630-08-0Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds ) Emission Limit 1: 0.1200 LB/H

Emission Limit 2: 0.5300 T/YR Standard Emission: NOT AVAILABLEDid factors, other then air pollution technology considerations influence the BACT decisions: UCase-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) NONE INDICATEDEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:





Case-by-Case Basis: N/A

Other Applicable Requirements: NSPS Control Method: (N) NONE INDICATEDEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes:


PROCESSNAME:

FURNACE EMISSION CAPS FOR 30 EMISSION POINTS


Primary Fuel: Throughput: Process Notes: INCLUDES OLEFINS FURNACES (EPNS: DB-101A&B, DB-101C&D, DB- 102A-D, DB-103-9, DDB-105, DDB-101A-D AND DDB-102A-D)

AND LIQUID FURNACES (EPN'S DDB-104-A&B)


CAS Number: PMTest Method: UnspecifiedPollutant Group(s): ( Particulate Matter (PM) ) Emission Limit 1: 25.5400 LB/H CAP PRIOR TO 3/31/04Emission Limit 2: 111.8600 T/YR CAP PRIOR TO 3/31/04Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown

Case-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) NONE INDICATEDEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: ADDITIONAL CAPS: 28.55 LB/H, 125.04 T/YR FROM 3/31/04 TO 6/30/06, 32.65 LB/H, 143.00 T/YR

AFTER 6/30/06



Test Method: UnspecifiedPollutant Group(s): ( Volatile Organic Compounds (VOC) ) Emission Limit 1: 18.4800 LB/H CAP PRIOR TO 3/31/04Emission Limit 2: 80.9500 T/YR CAP PRIOR TO 3/31/04Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown

Case-by-Case Basis: N/AOther Applicable Requirements: NSPS Control Method: (N) NONE INDICATEDEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: ADDITIONAL CAPS: 20.66 LB/H, 90.49 T/YR FROM 3/31/04 TO 6/30/06, 23.63 LB/H, 103.49 T/YR AFTER

6/30/06


CAS Number: 630-08-0Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds ) Emission Limit 1: 164.8000 LB/H CAP PRIOR TO 3/31/04Emission Limit 2: 721.8200 T/YR CAP PRIOR TO 3/31/04Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown

Case-by-Case Basis: BACT-PSDOther Applicable Requirements:Control Method: (N) NONE INDICATEDEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: ADDITIONAL CAPS: 184.22 LB/H, 806.90 T/YR FROM 3/31/04 TO 6/30/06, 200.78 LB/H, 879.41 T/YR

AFTER 6/30/06


CAS Number: 7446-09-5Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Sulfur (SOx) ) Emission Limit 1: 48.0000 LB/H CAP PRIOR TO 3/31/04

Emission Limit 2: 10.5100 T/YR CAP PRIOR TO 3/31/04Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown

Case-by-Case Basis: Other Case-by-CaseOther Applicable Requirements:Control Method: (N) NONE INDICATEDEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: ADDITIONAL CAPS: 53.66 LB/H, 11.75 T/YR FROM 3/31/04 TO 6/30/06, 61.37 LB/H, 13.44 T/YR AFTER

6/30/06


CAS Number: 7664-41-7Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds ) Emission Limit 1: LB/H CAP PRIOR TO 3/31/04Emission Limit 2: T/YR CAP PRIOR TO 3/31/04Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown

Case-by-Case Basis: Other Case-by-CaseOther Applicable Requirements:Control Method: (N) NONE INDICATEDEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: ADDITIONAL CAPS: 11.93 LB/H, 52.25 T/YR FROM 3/31/04 TO 6/30/06, 27.47 LB/H, 120.33 T/YR AFTER

6/30/06


CAS Number: 10102Test Method: UnspecifiedPollutant Group(s): ( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) ) Emission Limit 1: 512.1600 LB/H CAP PRIOR TO 3/31/04Emission Limit 2: 2243.2600 T/YR CAP PRIOR TO 3/31/04Standard Emission: 0.0500 LB/MMBTU COMBINEDDid factors, other then air pollution technology considerations influence the BACT decisions: Unknown

Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown

Case-by-Case Basis: Other Case-by-CaseOther Applicable Requirements:Control Method: (B) SCR, LOW NOX BURNERSEst. % Efficiency:Compliance Verified: UnknownPollutant/Compliance Notes: NOX ADDITIONAL CAPS: 401.91 LB/H, 1760.37 T/YR FROM 3/31/04 TO 6/30/06, 284.70 LB/H, 1246.99

T/YR, AFTER 6/30/06


PROCESS NAME: TANK EMISSION CAPS FOR 9 EMISSION POINTS


Primary Fuel: Throughput: Process Notes: SOURCES: AF-1101, AF-1102, AF-1901 THRU AF-1904, AF-3101, AF-3102, AF-3901

POLLUTANT NAME: Ethyl Benzene


Organic Compounds (VOC) ) Emission Limit 1: 0.0200 LB/H CAPEmission Limit 2: 0.0300 T/YR CAPStandard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown




Organic Compounds (VOC) ) Emission Limit 1: 0.7400 LB/H CAPEmission Limit 2: 2.2900 T/YR CAPStandard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown



CAS Number: 108-88-3Test Method: UnspecifiedPollutant Group(s): ( Hazardous Air Pollutants (HAP) , Organic Compounds (all) , Volatile Organic Compounds (VOC) ) Emission Limit 1: 0.1500 LB/H CAPEmission Limit 2: 0.3200 T/YR CAPStandard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown


POLLUTANT NAME: Hexane

CAS Number: 110-54-3Test Method: UnspecifiedPollutant Group(s): ( Hazardous Air Pollutants (HAP) , Organic Compounds (all) , Volatile Organic Compounds (VOC) ) Emission Limit 1: 0.4100 LB/H CAP

Emission Limit 1: 0.4100 LB/H CAPEmission Limit 2: 1.4700 T/YR CAPStandard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown


POLLUTANT NAME: Styrene

CAS Number: 100-42-5Test Method: UnspecifiedPollutant Group(s): ( Hazardous Air Pollutants (HAP) , Organic Compounds (all) , Volatile Organic Compounds (VOC) ) Emission Limit 1: 0.0100 LB/H CAPEmission Limit 2: 0.0200 T/YR CAPStandard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown


POLLUTANT NAME: o-Xylene

CAS Number: 1330-20-7Test Method: UnspecifiedPollutant Group(s): ( Hazardous Air Pollutants (HAP) , Organic Compounds (all) , Volatile Organic Compounds (VOC) ) Emission Limit 1: 0.0800 LB/H Emission Limit 2: 0.1000 T/YR Standard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown



CAS Number: VOCTest Method: UnspecifiedPollutant Group(s): ( Volatile Organic Compounds (VOC) ) Emission Limit 1: 11.0600 LB/H CAPEmission Limit 2: 45.1800 T/YR CAPStandard Emission: Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown


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